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Phase 1 Report Strategic Midwest Area Renewable Transmission

(SMARTransmission) Study Date: July 1, 2010 Prepared for: Project Sponsors Prepared by: Quanta Technology, a Division of

Quanta Services Primary Authors: Thomas J. Gentile, PE

[email protected] David C. Elizondo, PhD

[email protected] Swakshar Ray, PhD [email protected]

2

Acknowledgements

The authors would like to thank the many people who contributed to this report. Without their inputs this

study would not have been so successful. First we would like to thank the Sponsors of the

SMARTransmission study. They include Electric Transmission America (ETA), a transmission joint

venture between subsidiaries of American Electric Power and MidAmerican Energy Holdings Company;

American Transmission Company; Exelon Corporation; NorthWestern Energy; MidAmerican Energy

Company, a subsidiary of MidAmerican Energy Holdings Company; and Xcel Energy. The authors

would also like to thank the Midwest ISO, SPP, PJM, and MAPP for their invaluable support. A special

thanks to those who were on the Technical Review Committee and the Business Review Committee.

Their knowledge and direction was very much appreciated and invaluable. Finally, the authors would like

to thank Vivek Balasubramaniam, Scott Greene, Farbod Jahanbakhsh, Donald Morrow, Sasan Salem, and

Sercan Teleke of Quanta Technology whose timely contributions and extra efforts were very much

appreciated.

3

Table of Contents

1 Executive Summary................................................................................................................ 6 2 Phase 1 Overview ................................................................................................................. 11 3 Alternative Development ...................................................................................................... 12

3.1 3.1 Wind Models ............................................................................................................ 12 3.1.1 State and Federal RPS Requirements ..................................................................... 12 3.1.2 Base Wind Nameplate Capacity ............................................................................. 14 3.1.3 Energy Contribution of Wind Farms ...................................................................... 16 3.1.4 Base Wind Case ...................................................................................................... 16 3.1.5 Wind Generation Transfers..................................................................................... 17

4 2029 Conceptual EHV Transmission Overlay Alternatives ................................................. 18 4.1 Reliability Analysis ........................................................................................................ 18 4.2 Cost Analysis.................................................................................................................. 28 4.3 Alternative Selection Process......................................................................................... 29 4.4 Reliability Performance Metrics .................................................................................... 30 4.5 2029 Transmission Alternative 1 (345 kV) Performance Evaluation ............................ 31 4.6 Revised Alternatives ...................................................................................................... 31

4.6.1 High Voltage Direct Current (HVDC).................................................................... 31 4.6.2 Maps of Revised Conceptual EHV Transmission Overlay Alternatives ................ 32

4.7 Analysis of Revised Alternatives ................................................................................... 34 4.7.1 N-1-1 Analysis ........................................................................................................ 35

4.8 Futures Analysis............................................................................................................. 35 4.8.1 High Gas Future...................................................................................................... 36 4.8.2 Low Carbon Future ................................................................................................. 36

4.9 Sensitivity Analysis........................................................................................................ 37 4.9.1 Base Case Future Sensitivity Analysis ................................................................... 38 4.9.2 High Gas Future Sensitivity Analysis..................................................................... 39 4.9.3 Low Carbon Future Sensitivity Analysis................................................................ 40

5 Summary of Revised Alternatives ........................................................................................ 41 6 Sequencing of Alternatives ................................................................................................... 42

6.1 Sequencing Approach .................................................................................................... 42 6.2 Summary of RPS Values Used in Study ........................................................................ 43 6.3 2024 Sequencing of Alternatives ................................................................................... 44

6.3.1 2024 Double Contingency Analysis ....................................................................... 46 6.4 2019 Sequencing of Alternatives ................................................................................... 47

7 Phase 2: Economic Benefits Evaluation .............................................................................. 50 8 Conclusion ............................................................................................................................ 50 Appendix A: Key Assumptions .................................................................................................... 52 Appendix B: Study Methodology ................................................................................................. 81

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List of Figures

FIGURE 1-1: SMARTRANSMISSION STUDY AREA 6 FIGURE 1-2: 2029 REVISED CONCEPTUAL EHV TRANSMISSION ALTERNATIVE 2 8 FIGURE 1-3: 2029 REVISED CONCEPTUAL EHV TRANSMISSION ALTERNATIVE 5 9 FIGURE 1-4: 2029 REVISED CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 5A - INCLUDES HVDC 10 FIGURE 3-1: SMARTRANSMISSION STUDY WIND LOCATIONS 16 FIGURE 3-2: BASE WIND ON AND OFF PEAK RESOURCE COMPOSITION 17 FIGURE 3-3: THEORETICAL CUT SETS FOR POWER FLOW 17 FIGURE 4-1: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 1 19 FIGURE 4-2: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 2 20 FIGURE 4-3: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 3 21 FIGURE 4-4: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 4 22 FIGURE 4-5: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 5 23 FIGURE 4-6: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 6 24 FIGURE 4-7: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 7 25 FIGURE 4-8: CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 8 26 FIGURE 4-9: 2029 REVISED CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 2 32 FIGURE 4-10: 2029 REVISED CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 5 33 FIGURE 4-11: 2029 REVISED CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVE 5A - INCLUDES HVDC 34 FIGURE 5-1: COST ESTIMATES FOR CONCEPTUAL ALTERNATIVES 42 FIGURE 6-1: ALTERNATIVE 2 SHOWING LINES TO BE REMOVED FOR 2024 REVISED EHV TRANSMISSION OVERLAY 45 FIGURE 6-2: ALTERNATIVE 5 SHOWING LINES TO BE REMOVED FOR 2024 REVISED EHV TRANSMISSION OVERLAY 46 FIGURE 6-3: ALTERNATIVE 2 SHOWING LINES TO BE REMOVED FOR THE 2019 REVISED EHV TRANSMISSION

OVERLAY 48 FIGURE 6-4: ALTERNATIVE 2 SHOWING LINES TO BE REMOVED FOR THE 2019 REVISED EHV TRANSMISSION

OVERLAY 49

List of Tables

TABLE 3-1: SUMMARY OF STATE RENEWABLE PORTFOLIO STANDARDS 12 TABLE 3-2: ENERGY REQUIREMENT BY STATE FOR BASE WIND 2029 13 TABLE 3-3: NAMEPLATE WIND GENERATION POTENTIAL BY STATE 14 TABLE 3-4: TOTAL WIND BY STATE FOR BASE WIND 2029 15 TABLE 4-1: SUMMARY OF CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVES 27 TABLE 4-2: SUMMARY RESULTS OFF PEAK 27 TABLE 4-3: SUMMARY RESULTS ON PEAK 28 TABLE 4-4: COST ESTIMATES FOR CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVES 28 TABLE 4-5: COST SUMMARY FOR CONCEPTUAL EHV TRANSMISSION OVERLAY ALTERNATIVES 29 TABLE 4-6: RELIABILITY PERFORMANCE METRICS 30 TABLE 4-7: PERFORMANCE RESULTS OF CONCEPTUAL ALTERNATIVE 1 AT 36.1 GW OF WIND 31 TABLE 4-8: 2029 BASE WIND RESULTS FOR ON AND OFF PEAK CASES 35 TABLE 4-9: HIGH GAS RESULTS FOR ON AND OFF PEAK CASES 36 TABLE 4-10: LOW CARBON RESULTS FOR ON AND OFF PEAK CASES 37 TABLE 4-11: BASE WIND FUTURE RESULTS – GENERATION SENSITIVITIES 38 TABLE 4-12: BASE WIND FUTURE RESULTS – LOAD SENSITIVITIES 39 TABLE 4-13: HIGH GAS FUTURE RESULTS – GENERATION SENSITIVITIES 39 TABLE 4-14: HIGH GAS FUTURE RESULTS – LOAD SENSITIVITIES 40 TABLE 4-15: LOW CARBON FUTURE RESULTS – GENERATION SENSITIVITIES 40 TABLE 4-16: LOW CARBON FUTURE RESULTS – LOAD SENSITIVITIES 41 TABLE 5-1: HIGH LEVEL SUMMARY OF REVISED ALTERNATIVES 41 TABLE 5-2: COST SUMMARY FOR REVISED ALTERNATIVES 42 TABLE 6-1: RPS REQUIREMENTS BY STATE FOR STUDY YEARS 2029, 2024, 2019 43 TABLE 6-2: NAMEPLATE INSTALLED WIND GENERATION BY STATE FOR STUDY YEARS 2029, 2024, 2019 43 TABLE 6-3: 2024 BASE WIND RESULTS FOR ON AND OFF PEAK CASES 44 TABLE 6-4: 2024 BASE WIND RESULTS – GENERATION SENSITIVITIES 44

5

TABLE 6-5: 2019 BASE WIND RESULTS FOR ON AND OFF PEAK CASES 47 TABLE 6-6: 2019 BASE WIND RESULTS – GENERATION SENSITIVITIES 47

6

1 Executive Summary

The Strategic Midwest Area Renewable Transmission study, or SMARTransmission, was undertaken to

investigate transmission overlay possibilities that will facilitate the development of Midwest wind energy

generation and enable its delivery to the consumers within the study area. The study’s primary goal is to

develop a transmission plan that ensures reliable service, is environmentally friendly, and supports state

and national energy policies. SMARTransmission focuses 20 years into the future and incorporates

information from existing studies, as appropriate.

SMARTransmission is being sponsored by Electric Transmission America (ETA) – a transmission joint

venture between subsidiaries of American Electric Power and MidAmerican Energy Holdings Company,

American Transmission Company, Exelon Corporation, NorthWestern Energy, MidAmerican Energy

Company – a subsidiary of MidAmerican Energy Holdings Company – and Xcel Energy. The sponsor

group engaged Quanta Technology LLC (Quanta) to evaluate extra-high voltage (EHV) transmission

overlays and provide recommendations for new transmission development. The study area covering

portions of the Midwest ISO, PJM Interconnection and Southwest Power Pool footprints can be seen in

Figure 1-1. Given the geographical proximity of the sponsors’ respective systems, expertise in

transmission operations, and the concentration of renewable resources within their footprints, the sponsors

believe that a collaborative study is the most effective way to determine the study area’s current and

future transmission needs. Collectively, the sponsors bring unrivaled expertise to the needs of the

Midwestern electric system.

Figure 1-1: SMARTransmission Study Area

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SMARTransmission recognizes the critical role transmission infrastructure plays in the interconnection

and delivery of generation resources and seeks to ensure that the overall system is efficient and capable of

interconnecting wind and other generation resources. To this end, transmission needs were analyzed from

a regional perspective over a study area that encompasses some of the nation's best wind resources. The

information derived from reliability analyses is being used to recommend solutions for the expansion of

EHV transmission, integrated with the existing transmission system in areas of North Dakota, South

Dakota, Iowa, Indiana, Ohio, Illinois, Michigan, Minnesota, Nebraska, Missouri and Wisconsin.

The SMARTransmission study transcends traditional utility and RTO boundaries. As a result, the study

was designed to incorporate a high level of stakeholder input. Throughout the study process, the

SMARTransmission sponsors have held open meetings where interested stakeholders had the opportunity

to participate and provide input into the direction of the study. Over 100 participants representing

investor owned utilities, state utility commissions, the Federal Energy Regulatory Commission (FERC),

municipalities, wind developers, regional transmission organizations and others have participated in the

open meetings. To further encourage widespread participation, the study sponsors established a website

at www.smartstudy.biz to post meeting notices, study assumptions, milestones, deliverables and other

pertinent information as well as to provide a venue for interested stakeholders to ask questions.

SMARTransmission is being completed in two phases. The first phase of the study was focused on

identifying EHV transmission overlay alternatives and evaluating their cost and reliability performance,

and the second will be used to compare the economic benefits of those alternatives. During the first

phase of the study, the sponsor group designed eight conceptual EHV transmission overlay alternatives

that would enable the integration of 56.8 GW of nameplate wind generation within the study area. The

sponsors considered all voltages, including HVDC, when developing the eight conceptual EHV

transmission alternatives. The 56.8 GW of nameplate wind generation generally reflects a federal

Renewable Portfolio Standard (RPS) requirement of 20% with adjustments for those states that have

approved RPS requirements or goals in excess of 20%. Of these eight alternatives, one was exclusively

345 kV, two were a combination of 345 kV and 765 kV, and five were exclusively 765 kV.

Based on performance and cost, three modified EHV transmission overlay alternatives were selected for

futures and sensitivity analysis. The first potential alternative, shown in Figure 1-2: 2029 Revised

Conceptual EHV Transmission Alternative 2, was primarily a combination of 345 kV and 765 kV

facilities. The second potential alternative, shown in

Figure 1-3: 2029 Revised Conceptual EHV Transmission Alternative 5, was primarily 765 kV facilities.

The third potential alternative, shown in Figure 1-4: 2029 Revised Conceptual EHV Transmission

Overlay Alternative 5A - Includes HVDC, was primarily 765 kV with a long HVDC transmission line.

These three EHV transmission overlay alternatives performed better in the reliability analyses than the

other alternatives developed for the first phase of the study; however, this does not preclude different

long-range projects that accomplish similar system performance to the projects in these alternatives.

To help determine the prospective build out of the two potential EHV transmission overlay alternatives,

the sponsor group developed a sequencing approach for 2019 and 2024. Actual sequencing of the

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potential EHV transmission overlay will be dependent on where and when wind generation is developed

as well as the magnitude and distribution of load growth. The results have been shared with the

Southwest Power Pool (SPP), Midwest Independent System Operators (Midwest ISO), PJM

Interconnection, and Mid-Continent Area Power Pool (MAPP) to be used as input into their planning

processes.

Figure 1-2: 2029 Revised Conceptual EHV Transmission Alternative 2

9

Figure 1-3: 2029 Revised Conceptual EHV Transmission Alternative 5

10

Figure 1-4: 2029 Revised Conceptual EHV Transmission Overlay Alternative 5A - Includes HVDC

11

2 Phase 1 Overview

New transmission is a critical component of enabling the United States to effectively use the country’s

abundant renewable resources. During Phase 1 of the SMARTransmission study, the Sponsor group

evaluated eight conceptual EHV transmission overlay alternatives designed to enable the integration of

56.8 GW of nameplate wind generation within the study area. The 56.8 GW of wind generation generally

reflects a federal Renewable Portfolio Standard (RPS) requirement of 20% and adjustments for states with

approved RPS requirements or goals in excess of 20%.

In addition to considering RPS requirements, the sponsor group evaluated the wind generation potential

of each state in the study area. This information enabled the group to quantify the transmission needed to

enable the states to meet their RPS requirements and effectively use the country’s natural resources. Of

the eight conceptual EHV transmission overlay alternatives designed, one was primarily 345 kV, two

were a combination of 345 kV and 765 kV, and five were primarily 765 kV.

To determine the best performing options, Quanta Technology completed cost and reliability analysis for

each of the conceptual EHV transmission alternatives. Based on these results, the sponsor group chose

three conceptual EHV transmission alternatives for additional analysis. Modified versions of Alternative

2 (345 kV/765 kV), Alternative 5 (765 kV), and Alternative 5A (765 kV with an additional HVDC line

replacing one 765 kV line) were analyzed further using futures and sensitivities. The study analyzed high

gas and low carbon futures with sensitivities for high and low wind generation, SPP imports, and high and

low loads. This analysis showed that these three potential EHV transmission overlay alternatives work in

the futures and sensitivity analyses with manageable contingencies and mitigations.

In addition to running the futures and sensitivity analysis, the sponsor group completed a sequencing

analysis to determine the 2019 and 2024 build outs that would facilitate the development of the optimized

2029 potential EHV transmission overlay alternatives. The results of both the sequencing and the 2029

analysis will be shared with the Regional Transmission Organizations to serve as input to the regional

transmission planning processes and to identify required projects. The timing and sequencing of these

alternatives is intended to be flexible and can change based on local and regional needs.

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3 Alternative Development

3.1 3.1 Wind Models

Wind generation assumptions were crucial to SMARTransmission’s EHV analysis. Quanta Technology

and the sponsor group evaluated state and federal RPS requirements, estimated wind nameplate potential,

and the future energy contribution of wind farms to develop the wind assumptions used for the study.

3.1.1 State and Federal RPS Requirements

State RPS requirements call for states to obtain certain percentages of their retail energy sales from

renewable sources by certain dates. Transmission will play an important role in enabling states to meet

these requirements. The SMARTransmission RPS assumptions for 2029 reflect a federal RPS

requirement of 20% with adjustments for those states that have approved RPS requirements or goals in

excess of 20%. State RPS mandates used in this study were obtained from the Database of State

Incentives for Renewable and Efficiency. This information is summarized in Table 3-1.

Table 3-1: Summary of State Renewable Portfolio Standards

State Summary of RPS

Requirements SMARTransmission RPS

Assumptions for 2029

Iowa 2% 2011 or 105 MW 20%

Illinois 25% by 2025 25%

Indiana None 20%

Michigan 10% 2015 20%

Minnesota1 25% by 2025 27.5%

Missouri 15% 2021 20%

North Dakota 10% 2015 20%

Nebraska None 20%

Ohio 25% by 2025 25%

South Dakota 10% 2015 20%

Wisconsin 10% 2013 20% 2020 25% 2025

25%

Based on the SMARTransmission RPS assumptions, the study sponsors determined the renewable energy

requirements for each state as shown in Table 3-2.

1 Xcel Energy has a 30% RPS requirement and the rest of the state has a 25% RPS requirement. Because Xcel Energy is approximately half the load in the state, the RPS in Minnesota was assumed to be 27.5% for the entire state.

Table 3-2: Energy Requirement by State for Base Wind 2029

IA IL IN MI MN MO ND NE OH SD WI Federal 20% - State RPS - Utility RPS in %

20% 25% 20% 20% 28% 20% 20% 20% 25% 20% 25%

% of energy renewable from wind (MWh)

80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%

Average Capacity Factor (Supplied from MISO 3 Year Capacity Factor Statistics

0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3

High Wind State- yes/no? (high wind state if capacity factor >36%)

Yes No No No Yes No Yes Yes No Yes No

Energy Growth (average US) 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.0% 1.1%

Energy Usage by US State (MWh) / 2007 EIA

45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300

Total energy usage extrapolated assuming constant growth (billion MWh) (2029)

56,347,693 181,797,163 136,196,996 136,043,397 84,928,434 106,464,095 14,819,207 35,161,231 201,358,714 13,198,097 90,703,255

% for RPS renewable (MWh) - 11,269,539 45,449,291 27,239,399 27,208,679 23,355,319 21,292,819 2,963,841 7,032,246 50,339,679 2,639,619 22,675,814

RPS energy from wind (MWh) 9,015,631 34,086,968 21,791,519 21,766,944 18,684,256 17,034,255 2,371,073 5,625,797 25,169,839 2,111,696 14,739,279

Total 172,397,256

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3.1.2 Base Wind Nameplate Capacity

The sponsor group thoroughly evaluated the wind generation potential of each state in the study area since

this information was necessary to quantify the transmission requirements that would enable the states to

meet the RPS requirements in the study. The study team believed that the state wind potential should be

based on consistent assumptions throughout the study area. In March 2008, the National Renewable

Energy Laboratory (NREL) engaged AWS Truewind, LLC to develop wind resource and plant output

data to be used for the Eastern Wind Integration Transmission Study (EWITS)2. SMARTransmission used

the state wind capacities developed by NREL to allocate the wind generation potential in the study area to

each of the states3.

Table 3-4 shows the calculation for the nameplate wind capacity needed to meet state RPS requirements.

These capacity requirements were based on a calculation that assumed wind energy would provide

approximately 80% of the renewable requirements of each state. The remainder was assumed to be

achieved through other means. This allows for a moderate amount of renewable energy to be sourced

from non-wind energy sources. For those states with in-state renewable generation mandates or goals,

SMARTransmission included the state-specific requirements. For example, Ohio requires at least 50% of

its renewable energy requirement to be met by in-state facilities, while the remaining 50% is permitted to

be achieved with resources that can be shown to be deliverable into the state. The 50% that could be

generated outside of Ohio was allocated to other states within the study area. Similarly, Illinois has a

provision that gives preference to resources within Illinois and adjoining states.

Existing wind generation was subtracted from the 2029 renewable

energy requirement to establish the incremental wind generation

needed. The incremental wind generation in the study area was then

allocated among the states in proportion to the wind capacity of the

NREL Selected Sites shown in Table 3-3. Column D of Table 3-4

shows that Iowa and North Dakota already meet approximately 80%

of the assumed 20% Federal RPS requirements that were modeled

because the existing wind installations exceed the 2029 requirements.

Column I shows that, by 2029, there will be enough excess wind

energy in Iowa, North Dakota, Nebraska, and South Dakota to satisfy

the requirements of those states that cannot meet their renewable

energy requirements with in-state resources. The total nameplate

wind generation value for all the states in the study area is 56.8 GW.

This includes 9.3 GW of wind that was online as of May 2009. Figure 3-1 shows the assumed locations

and magnitudes of the wind farms in the study area.

2 The goal of EWITS was to evaluate the impact on the electric power system of increasing wind generation required to meet 20% and 30% of retail electric energy sales in the study region. 3 The methods used to develop the wind sites and capacities by state are described on the NREL website

(http://wind.nrel.gov/public/EWITS).

Table 3-3: Nameplate Wind Generation Potential by State

State NREL Capacity Distribution

(MW)

Iowa 52,575

Illinois 42,029

Indiana 30,965

Michigan 23,944

Minnesota 61,480

Missouri 10,138

North Dakota 32,138

Nebraska 48,471

Ohio 17,445

South Dakota 48,547

Wisconsin 20,494

Table 3-4: Total Wind by State for Base Wind 2029

A B C D E F G H I J

Energy to meet ~80%

RPS Requirement

Existing Wind as of May 2009

Incremental wind to meet ~80% RPS

Requirement

Incremental Wind

Prorate of NREL by

State

Energy (Import) / Export by

State

% RPS Wind

Generated In-State

Incremental Wind

Prorate of NREL by

State

Energy (Import) / Export by State

Total Wind by State

Existing + Incremental

State MWh MWh (B-C) MWh MWh

(E-D) MWh % MW MW MW

IA 9,015,631 10,109,338 (1,093,707) 12,055,001 13,148,708 100% 3,641 3,857 6,694

IL 34,086,968 4,441,320 29,645,648 16,370,614 (13,275,034) 61% 6,229 (3,894) 7,919

IN 21,791,519 2,946,645 18,844,874 7,238,053 (11,606,822) 47% 2,542 (3,404) 3,577

MI 21,766,944 342,402 21,424,541 21,424,541 0 100% 8,072 0 8,201

MN 18,684,256 5,739,683 12,944,572 12,944,572 0 100% 4,071 0 5,876

MO 17,034,255 958,221 16,076,034 8,562,158 (7,513,876) 56% 2,761 (2,204) 3,070

ND 2,371,073 2,674,130 (303,057) 14,176,611 14,479,667 100% 4,066 4,247 4,833

NE 5,625,797 540,133 5,085,664 17,801,633 12,715,968 100% 5,043 3,730 5,196

OH 25,169,839 18,641 25,151,198 12,575,599 (12,575,599) 50% 4,722 (3,689) 4,729

SD 2,111,696 1,019,244 1,092,452 13,873,332 12,780,880 100% 3,920 3,749 4,208

WI 14,739,279 1,500,588 13,238,691 5,084,796 (8,153,895) 45% 1,935 (2,392) 2,506

Total 172,397,256 30,290,346 142,106,911 142,106,911 47,002 0 56,809

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Figure 3-1: SMARTransmission Study Wind Locations

3.1.3 Energy Contribution of Wind Farms

Traditional reliability studies focus on summer peak hours since the load is generally at its highest during

those times, and the transmission facilities are stressed. Wind generation often has limited availability

during those hours. To account for the wind generation profile, this study assumes a wind contribution of

20% of the installed nameplate capacity for the summer peak case. Since wind farms generally produce

more energy during off peak hours, (approximately 70% of summer peak), the study assumed a wind

contribution of 90% during those hours. During periods of high wind generation and low consumer

loads, the EHV overlay facilities are expected to be most heavily loaded, consistent with experience in

real-time operations. For both on and off peak hours, reliability studies were conducted to ensure thermal

loading and voltage limits would remain within acceptable levels.

3.1.4 Base Wind Case

The nameplate wind generation capacity required to meet the SMARTransmission RPS assumptions was

56.8 GW. Wind contribution in the off peak case (90% of 56.8 GW or approximately 51.1 GW) as

compared to the on peak case (20% of 56.8 GW or approximately 11.4 GW) changes the pattern of the

power flow across the study area and stresses the system in different locations. Generation resource

allocations for the on and off peak base wind future are shown in Figure 3-2.

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Figure 3-2: Base Wind On and Off Peak Resource Composition

3.1.5 Wind Generation Transfers

One of the key drivers of the SMARTransmission study is to support renewable energy development and

facilitate the transportation of clean energy to consumers throughout the study area. As a result, it is

important to understand the flow of wind power across the study area. The five theoretical cut sets shown

in Figure 3-3 were developed to illustrate the potential flows of wind power from those states that have

wind generation potential in excess of that needed to meet their own renewable energy requirements. The

initial eight conceptual EHV transmission overlay alternatives were designed by determining the

transmission capacity needed to deliver power across each cut set. For example, to transport the eight

gigawatts (GW) of power as shown in the first cut set, the transmission system would need to be designed

to carry approximately eight GW from the first cut set to the second cut set. Power will flow on both the

EHV overlay and the existing transmission system.

Figure 3-3: Theoretical Cut Sets for Power Flow

Nuclear11%

Coal46%

Wind5%

Other + Unknown

18%

Hydro2%

Oil2%

Gas16%

Base Wind On Peak

Nuclear15%

Coal49%

Wind27%

Other + Unknown

2%

Hydro3%

Oil0%

Gas4%

Base Wind Off Peak

Nuclear11%

Coal46%

Wind5%

Other + Unknown

18%

Hydro2%

Oil2%

Gas16%

Base Wind On Peak

Nuclear11%

Coal46%

Wind5%

Other + Unknown

18%

Hydro2%

Oil2%

Gas16%

Base Wind On Peak

Nuclear15%

Coal49%

Wind27%

Other + Unknown

2%

Hydro3%

Oil0%

Gas4%

Base Wind Off Peak

18

4 2029 Conceptual EHV Transmission Overlay Alternatives

During the first phase, the study group identified eight conceptual EHV transmission overlay alternatives,

intended to facilitate the integration of 56.8 GW of nameplate wind generation within the study area. The

alternatives were chosen based on their projected ability to meet the wind power transfer requirements

shown in the cut sets in Figure 3-3. Figure 4-1 through Figure 4-8 show the conceptual EHV

transmission overlays that were developed for 2029. Of these eight conceptual EHV transmission overlay

alternatives, one was exclusively 345 kV, two were a combination of 345 kV and 765 kV, and five were

exclusively 765 kV. When developing the eight conceptual EHV transmission overlay alternatives, the

group considered all voltages including HVDC.

4.1 Reliability Analysis

Reliability analysis was performed on the eight conceptual EHV transmission overlay alternatives in

order to identify and select the best performing alternatives for further evaluation. This analysis included

the simulations of single contingencies4 for transmission facilities within the study area that have voltages

of 345 kV and above. The conceptual EHV transmission overlay alternatives were designed to meet

single contingency criteria. The alternatives were evaluated per the planning criteria described in

Appendix A (Section 14). Transmission facilities with voltages of 200 kV and above were monitored for

thermal and voltage violations. A high level summary of their performance is provided with each figure.

4 A single contingency (N-1) simulation is used to evaluate the system conditions when one transmission facility is out of service.

19

Figure 4-1: Conceptual EHV Transmission Overlay Alternative 1

• Approximately 16,300 miles of 345 kV double circuit (~32,600 circuit miles)

• Second highest number of non-solving contingencies on EHV overlay for off peak case

• Long 345 kV lines from St Joseph to Rockport

• Five major paths west to east across cut set 4 shown in Figure 3-3

20


• No non-solving contingencies on EHV overlay for off peak case

• Four major paths west to east across cut set 4 shown in Figure 3-3

21


• Long lines between areas which result in reliability issues

• Several non-solving contingencies

• Three major paths west to east across cut set 4 shown in Figure 3-3.

22


• Nebraska transmission system not optimized. Alternative 2 addresses this issue.

• Iowa has contingency issues.

• Long 765 kV line from St Joseph to Rockport.

23


• Large loop in the northwestern portion of the study area results in minor contingency issues.

• Contingency issues can be addressed through modifications.

• Four major paths west to east across cut set 4 shown in Figure 3-3.

24


• Most non-solving contingencies on EHV overlays as compared to other alternatives.

• Substantial upgrades required to mitigate non-solving contingencies.

25


• No non-solving contingencies on EHV overlay for off peak case.


26


• Numerous non-solving contingencies on EHV overlays as compared to other alternatives.

• Location of non-solving contingencies will necessitate substantial upgrades to mitigate non-solving contingencies.


27

Table 4-1 provides a summary of the important features of each of the conceptual EHV transmission

overlay alternatives.

Table 4-1: Summary of Conceptual EHV Transmission Overlay Alternatives

High Level Summary

Alt

1 Alt

2 Alt

3 Alt

4 Alt

5 Alt

6 Alt

7 Alt

8

Single circuit 345 kV lines (number of lines) 225 96 8 92 12 8 6 8

Total 345 kV double circuit structure miles 16,271 7,156 339 7,734 350 339 339 339

Single circuit 765 kV lines (number of lines) 0 30 45 30 52 56 48 48

Total 765 kV circuit miles 0 3,829 6,917 4,037 7,887 8,253 7,264 6,707

Total construction miles 16,271 10,985 7,256 11,771 8,237 8,592 7,603 7,046

Total acreage 295,842 222,930 173,848 238,497 197,546 206,244 182,244 168,771

765/345 kV Transformers 1 18 28 16 25 32 33 30

345/230 kV Transformers 0 3 3 3 3 3 3 3

345 kV stations 150 64 5 61 8 5 5 5

765 kV stations 0 20 30 20 32 37 32 32

HVDC yes no yes yes no yes no Yes

Major river crossings 11 6 9 9 9 9 9 7

Single contingency simulations were completed for both on and off peak loading conditions. Table 4-2

and Table 4-3 show the number of N-1 contingencies on the existing EHV system as well as the EHV

overlay elements that did not solve for each conceptual EHV transmission overlay alternative. A lower

number of non-solving contingencies indicates a more robust transmission alternative. This means that

the overlay alternative will require fewer modifications to alleviate performance issues. For example, at

56.8 GW of nameplate wind generation for the off peak case, Alternative 2 does not have any non-solving

contingencies on the EHV overlay for single system contingency conditions, while Alternative 6 has 15

non-solving contingencies. This means that Alternative 2 can deliver the 56.8 GW of wind generation

under single contingency conditions while Alternative 6 will need modifications, some of which may

constitute significant upgrades to deliver the generation under single contingencies. Any number other

than zero in the tables indicates that the alternative will require modifications to eliminate the violations.

Table 4-2: Summary Results Off peak

Non-Solving Contingencies

Alt

1 Alt

2 Alt

3 Alt

4 Alt

5 Alt

6 Alt

7 Alt

8

EHV Overlay 14 0 4 4 2 15 0 9

Existing EHV Facilities 9 1 2 11 2 1 3 2

28

Table 4-3: Summary Results On peak

Non-Solving Contingencies

Alt

1 Alt

2 Alt

3 Alt

4 Alt

5 Alt

6 Alt

7 Alt

8

EHV Overlay 0 0 2 0 2 3 1 1

Existing EHV Facilities 8 11 8 8 7 9 9 24

4.2 Cost Analysis

Table 4-4 shows transmission station and line costs that were developed using common estimating

philosophies. The costs were developed using up-to-date standards and design criteria, material costs

from similar projects, and optimized line and station designs for both flat and mountainous terrain. The

costs were also designed to include environmental and siting requirements.

Table 4-4: Cost Estimates for Conceptual EHV Transmission Overlay Alternatives

Element $M Transmission Lines (includes right-of-way costs)

Single circuit 345 kV (USD / mile) 1.50

Double circuit 345 kV (USD / mile) 1.97


Transformers

345/230 kV, 500 MVA (USD / unit) 6.5

765/345 kV, 1000 MVA (USD / unit) 12.0

765/345 kV, 2250 MVA (USD / unit) 21.0

Network Stations (does not include land costs)

345 kV (USD / station) 11.8


Major River crossings 7.0

HVDC Undersea Cable (USD / mile) 9.0

HVDC Overhead (USD / mile) 5.0

Table 4-5 applies the costs in Table 4-4 to the components in Table 4-1 to calculate the estimated cost of

each conceptual EHV transmission overlay alternative.

29

Table 4-5: Cost Summary for Conceptual EHV Transmission Overlay Alternatives

Estimated Costs ($ M)

Alt 1

Alt 2

Alt 3

Alt 4

Alt 5

Alt 6

Alt 7

Alt 8

345 kV Double Circuit Lines $32,054 $14,098 $668 $15,237 $689 $668 $668 $668

765 kV Lines $0 $10,375 $18,745 $10,941 $21,373 $22,366 $19,687 $18,177

Total Transmission Lines $32,054 $24,474 $19,413 $26,178 $22,061 $23,034 $20,355 $18,845

Transformer Costs

765/345 kV Transformers $21 $378 $588 $336 $525 $672 $693 $630

345/230 kV Transformers $0 $17 $17 $17 $17 $17 $17 $17

Total Transformation $21 $395 $605 $353 $542 $689 $710 $647

345 kV Network Substation/Station $1,770 $755 $59 $720 $94 $59 $59 $59

765 kV Network Substation/Station $0 $502 $753 $502 $803 $929 $803 $803

Total Costs Substation/Station $1,770 $1,257 $812 $1,222 $898 $988 $862 $862

HVDC $1,810 - $1,080 $810 - $1,080 - $2,480

River Crossings $77 $42 $63 $63 $63 $63 $63 $49

Preliminary Estimated Costs $35,732 $26,168 $21,973 $28,625 $23,564 $25,854 $21,990 $22,883

4.3 Alternative Selection Process

Based on the cost and reliability analysis, five of the eight conceptual EHV transmission overlay

alternatives were eliminated from further study. One combination 345 kV/765 kV alternative (Alternative

4) was eliminated because it had the second highest cost estimate and a significantly higher number of

reliability issues as compared to some of the other alternatives. Three 765 kV-only options (Alternatives

3, 6, and 8) were eliminated because they had a significant number of reliability issues as compared to

some of the other alternatives. Mitigating the issues would have required substantial upgrades and added

to the cost of those alternatives.

Based on the cut sets, the 345 kV alternative (Alternative 1) provided sufficient power transfer capability

to move 56.8 GW of wind. This alternative was more expensive and was not as reliable as the other

options during single contingency simulations so it was not chosen for further consideration at the 56.8

GW level. This option was further studied to determine its performance at a lower level of wind (36.1

GW nameplate) which is somewhat more reflective of current state renewable energy standards, rather

than the 56.8 GW of wind that reflects 80% of the energy required to meet a base level of 20% federal

Renewable Portfolio standard in the study area. Additional information regarding the Low Wind scenario

can be found in Section 16.2 of the Appendix.

Alternatives 2, 5 and 7 were selected for further evaluation.

30

4.4 Reliability Performance Metrics

The SMARTransmission team developed a series of metrics to rank the performance of Alternatives 2, 5,

and 7. Table 4-6 describes these metrics. The EHV overlay was designed to support the integration of

56.8 GW of wind power, while ensuring there were no thermal or voltage violations under normal (with

all facilities in service) and single contingency conditions. The 56.8 GW of wind generation changes the

power flow patterns, resulting in new reliability issues on the existing system facilities. Violations on the

existing system are more localized and are highly dependent upon the location and magnitude of the wind

generation facilities. When the locations and magnitudes of future wind farms are determined, the RTOs

will perform generation interconnection studies to resolve potential system issues associated with their

development. The study used the violations on the existing system for alternative comparison purposes

only.

Table 4-6: Reliability Performance Metrics Simulations Description

Overlay voltage violations : All

facilities in-service

EHV overlay bus voltages that operate outside the system voltage limits (Table A-5) with all transmission facilities in service.

Overlay thermal violations: All

facilities in-service

EHV overlay facilities that exceed their applicable thermal ratings with all transmission facilities in service.

Non Solving Contingencies:

EHV Overlay

Single contingencies of EHV Overlay facilities that result in non-convergent solutions5.

Overlay thermal violations: Overlay

N-1

EHV overlay facilities that exceed the applicable thermal ratings following the loss of a single EHV overlay facility.

Overlay voltage violations: Overlay

N-1

EHV overlay bus voltages that operate outside the system voltage limits (Table A-5) following the loss of a single EHV overlay facility.

Existing System Thermal Violations: All facilities in-service

Existing transmission facilities that exceed their applicable thermal ratings with all transmission facilities in service.

Non-solving contingencies:

Existing System Single contingencies of existing transmission facilities that result in non-convergent solutions.

Existing System thermal violations: Overlay N-1

Existing transmission facilities that exceed their applicable thermal ratings following the loss of a single EHV Overlay facility.

Existing System thermal violations: Existing System N-1

Existing transmission facilities that exceed their applicable thermal ratings following the loss of other existing transmission facilities taken one at a time.

5 The sum of all power flows at any particular node must be zero or reasonably close to zero. A convergent solution is achieved by a mathematical algorithm which iterates with the objective of reducing the sum of power flows to some acceptable small value called mismatch tolerance. A non-convergent solution occurs when mismatch tolerance is not met.

31

4.5 2029 Transmission Alternative 1 (345 kV) Performance Evaluation

Quanta analyzed the performance of the 345 kV option at lower wind levels. The performance of the 345

kV alternative is shown in Table 4-7. Sensitivity analysis shows that the 345 kV alternative would be a

feasible alternative to support 36.1 GW of wind generation, although the cost would be significantly

higher than the alternatives selected for further analysis.

Table 4-7: Performance results of Conceptual Alternative 1 at 36.1 GW of Wind

Row Simulations Violations

1 Overlay voltage violations: All facilities in-service 0

2 Overlay thermal violations: All facilities in-service 0

3 Non-solving Overlay N-1 0

4 Overlay thermal violations: Overlay N-1 0

5 Overlay voltage violations: Overlay N-1 0

6 Existing System Thermal violations: All facilities in-service 3

7 Non-solving Existing System N-1 1

8 Existing System thermal violations: Overlay N-1 0

9 Existing System thermal violations: Existing System N-1 14

4.6 Revised Alternatives

Alternatives 2, 5, and 7 were optimized for reliability performance. For example, the analysis of

conceptual Alternative 5 shows two non-solving contingencies on the conceptual EHV Overlay. These

were addressed by adding a 765 kV transmission line from Bison (ND) to Helena (MN) to Belvidere

(MN). Lightly loaded facilities were removed as long as reliability was not negatively impacted. For

example, St. Joseph (MO) – Rockport (IN) 765 kV transmission line was eliminated from the alternatives.

In addition, an HVDC line across Lake Michigan was added. The HVDC line provides another reliable

east-west tie and alleviates constraints associated with the rapidly developing wind generation in Eastern

Wisconsin. Changes to optimize Alternative 7 made it similar to Alternative 5. As a result, Alternative 7

was removed from further evaluation.

4.6.1 High Voltage Direct Current (HVDC)

HVDC additions to the conceptual alternatives were based on finding natural applications within the

study area. Some of the natural applications for HVDC include linking two asynchronous grids and

moving power over long distances, including underground and underwater.

Applications were determined by the potential locations of wind generation collection systems, EHV

overlay connections to the local transmission systems, and renewable energy costs and requirements.

Underwater cables across Lake Michigan (approximately 91 miles of ±400 kV, 1200 MW) and a long-

distance transmission line between Adair County and Sullivan Stations (approximately 385 miles of ±400

kV, 2000 MW) were incorporated into the study.

32

4.6.2 Maps of Revised Conceptual EHV Transmission Overlay Alternatives

Alternative 5 was modified to include an HVDC line from Adair County to Sullivan Station and selected

for further study as Alternative 5A. The three alternatives were optimized to eliminate the lightly loaded

lines and are shown in Figures 4-9 through 4-11.

Figure 4-9: 2029 Revised Conceptual EHV Transmission Overlay Alternative 2

33

Figure 4-10: 2029 Revised Conceptual EHV Transmission Overlay Alternative 5

34

Figure 4-11: 2029 Revised Conceptual EHV Transmission Overlay Alternative 5A - Includes HVDC

4.7 Analysis of Revised Alternatives

Reliability analysis was performed on the revised alternatives. Single contingency analysis was performed

per the planning criteria described in Appendix A. Double contingency6 analysis was performed to test

the strength of the overlays under higher stress conditions and was used to compare the alternatives.

Transmission facilities with voltages of 200 kV and above were monitored for thermal and voltage

violations.

The single contingency analysis confirmed that the modifications made to the revised alternatives

alleviated the violations in the Alternative 5 overlay as shown in Table 4-2. The revised overlay

alternatives do not show any significant steady state thermal or voltage constraints for the base wind on

and off peak cases. Rows 1 through 5 in Table 4-8 reflect the revised EHV overlay violations that result

from outages on the existing or revised EHV overlays. Voltage violations in Row 5 for Alternative 2 in

the off peak case and Alternatives 2, 5, and 5A in the on peak case are not of major concern because those

violations can be eliminated with capacitors or reactors. Rows 6 through 9 reflect existing facility

6 A double contingency (N-2) simulation is used to evaluate the system conditions when two transmission facilities are out of service at the same time.

35

violations that result from outages on the existing or revised EHV overlays. These violations are shown

for completeness and are generally a function of load growth or wind resource locations.

Table 4-8: 2029 Base Wind Results for On and Off Peak Cases

Off Peak On Peak

Row Number of Violations Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A

1 Overlay voltage violations: All facilities in-service 0 0 0 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0 0 0

3 Non-solving Overlay N-1 0 0 0 0 0 0

4 Overlay thermal violations: Overlay N-1 0 0 0 0 0 0

5 Overlay voltage violations: Overlay N-1 1 0 0 2 1 1

6 Existing System Thermal violations: All facilities in-service 7 8 8 10 12 13

7 Non-solving Existing System N-1 4 3 3 12 12 12

8 Existing System thermal violations: Overlay N-1 5 21 23 3 6 4

9 Existing System thermal violations: Existing System N-1 54 56 56 106 113 85

The above analysis shows that Alternatives 2, 5, and 5A could support 56.8 GW of nameplate wind

generation. Mitigations for violations on the existing transmission system are expected to be

recommended during the annual RTO and local utility planning studies.

4.7.1 N-1-1 Analysis

Double contingency (N-2) analysis was performed on the revised alternatives to test their robustness.

The sponsor group chose off peak models to perform the analysis since the off peak periods are

characterized by high wind generation, low consumer loads, and heavily loaded EHV facilities. Double

contingencies were simulated on the EHV Overlay elements and existing EHV facilities critical to the

study. Consistent with NERC Planning Criteria, the N-2 contingencies were simulated using N-1-1

contingency7 analysis on the revised EHV Overlay. Some of these N-1-1 contingencies resulted in non-

convergent solutions. For example, approximately 1.2 GW of generation was curtailed in South Dakota

for the Hankinson (ND) to Helena (ND) and New Sub MN1 (MN) to Helena (MN) 765 kV line outages to

obtain a convergent solution in Alternative 2. Similarly, approximately 2.5 GW of generation was re-

dispatched in North and South Dakota for the Bison (ND) to Helena (MN) and Bison (ND) to Chisago

County (MN) 765 kV line outages in Alternative 5 and 5A. The reliability issues occurring on the existing

system are expected to be addressed by generation re-dispatch and should be further evaluated in annual

RTO or local utility planning studies.

4.8 Futures Analysis

Transmission Alternatives 2, 5, and 5A were designed to meet performance criteria under base wind

assumptions. In addition to the 2029 base cases, two additional generation future cases (High Gas and

Low Carbon) were created for analysis. Due to uncertainties associated with economic and political

conditions, long range transmission plans should be based on a range of assumed scenarios or Futures.

The study evaluated the transmission alternatives under the High Gas and Low Carbon Futures to assess

the robustness of each alternative and compare their performances.

7 N-1-1 is a double contingency that allows for system adjustments after the first contingency and before the second. System adjustments include but are not limited to generation re-dispatch and load curtailment.

36

4.8.1 High Gas Future

The High Gas Future assumes that generation from gas facilities will increase faster than that from other

conventional facilities. As compared to the base case, this future assumes that gas generation will

increase from 40.0 GW to 51.7 GW. Incremental gas generation was added based on previous studies, gas

line locations, and RTO queues. Coal units were reduced proportionally throughout the study area. The

results of the N-1 contingency analysis for the 2029 High Gas Future are shown in Table 4-9 for both the

on and off peak base cases. This analysis indicates that with the exception of some minor deficiencies,

the alternatives will perform well under the High Gas Future scenario.

Table 4-9: High Gas Results for On and Off Peak Cases

2029 High Gas Future Off Peak On Peak

Row Simulation Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A



3 Overlay unsolvable: Overlay N-1 0 0 0 0 0 0




7 Existing System unsolvable: All N-1 5 3 3 11 13 13



4.8.2 Low Carbon Future

The Low Carbon Future is based on the premise of decreasing carbon emitting generation resources and

increasing hydro, nuclear, and wind generation. The scenario assumes that 29 coal units, totaling

approximately 2 GW, were retired. Coal generation was reduced by another 9 GW by lowering the output

of remaining units. Additional information can be found in Section 1.3 of Appendix B.

The results of the N-1 contingency analysis for the 2029 Low Carbon Future is shown in Table 4-10. This

analysis indicates that with the exception of some voltage deficiencies, the alternatives will perform well

under the Low Carbon Future scenario. The actual locations of coal plant retirements as well as the

location and size of new generation resources should be monitored as they could have a significant impact

on the results of the Low Carbon Future.

37

Table 4-10: Low Carbon Results for On and Off Peak Cases

Off Peak On Peak

Row Simulation Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A










4.9 Sensitivity Analysis

Three sensitivities were run to determine how changes to a key assumption in the 2029 base cases impacts

the performance of the transmission alternatives. The sensitivities studied were a High Wind generation

case, a Low Wind generation case and an SPP Import case. The sensitivity cases were developed from

the off peak future cases. The High Wind generation sensitivity was designed to address higher than

expected energy usage associated with economic growth during the 20-year period. For this sensitivity,

renewable requirements were based on 2% energy growth as opposed to the 1% assumed in the base case.

This results in a High Wind nameplate generation of 70.5 GW. See Table A-9 and Table A-10 in

Appendix A for additional information. Conversely, the Low Wind generation sensitivity was designed to

address uncertainties around renewable energy polices and take into account lower than anticipated

energy growth during the 20-year period. Based on existing RPS requirements and energy growth of

0.3% as opposed to 1% in the base case, the Low Wind nameplate generation was calculated to be 36.1

GW. See Table A-11 and Table A-12 in Appendix A for additional information. Given the significant

wind activity in SPP, Quanta performed a sensitivity to provide insight into the contribution of the SPP

wind to the eastern market. For this sensitivity, approximately 6 GW of wind generation was imported

from the SPP region. Wind generation locations were based on results from the SPP Overlay Study8

completed by Quanta in 2008. These sensitivities were run for the off peak future cases because they are

characterized by high wind generation, low consumer loads, and heavily loaded EHV facilities.

Additionally, higher and lower than forecasted load growth sensitivities were used to assess a range of

possible future load conditions. These sensitivities were applied to on peak future cases due to higher

demand levels as compared to off peak cases. For the high load sensitivity, the 2029 base case demand

levels were increased by 1% resulting in a load level of 168 GW. Table 4-11 shows that Alternatives 5

and 5 A perform adequately, and Alternative 2 shows stress under the high load sensitivity. For the low

load sensitivity, the 2029 base case demand levels were decreased by 5%9, resulting in load levels of

158.2 GW. An analysis of this sensitivity was performed on the Base Wind Future case to gain insight

9 In general, MISO considers a 5% increase and decrease in load levels to account for uncertainties in load projections.

38

into the lightly loaded transmission lines that might not be required under the Low Load scenario. Further

analysis will be required to determine if the overlay performs adequately under contingency conditions

with the lightly loaded lines removed.

4.9.1 Base Case Future Sensitivity Analysis

The High Wind and SPP Import sensitivity results in Table 4-11 show several unsolved contingencies

(Row 3) in all the alternatives. These results are indicative of a transmission network that is stressed and

is exceeding its capability. The locations and magnitude of new wind farms as well as load growth should

be monitored as they could have a significant impact on the results. The Alternatives perform adequately

under the Low Wind sensitivity.

Table 4-11: Base Wind Future Results – Generation Sensitivities

High Wind Imports from SPP Low Wind

Row Base Case Wind Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A

1 Overlay voltage violations: All facilities in-service 0 0 0 0 0 2 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0 0 0 0 0 0

3 Overlay unsolvable: Overlay N-1 14 7 12 13 3 4 0 0 0

4 Overlay thermal violations: Overlay N-1 4 3 1 0 0 0 0 0 0

5 Overlay voltage violations: Overlay N-1 6 8 3 2 1 1 8 11 11

6 Existing System Thermal violations: All facilities in-service 18 18 20 11 9 11 2 2 2

7 Existing System unsolvable: All N-1 8 3 3 22 5 2 4 4 3

8 Existing System thermal violations: Overlay N-1 11 93 68 4 39 46 1 3 3

9 Existing System thermal violations: Existing System N-1 58 244 195 95 94 98 23 12 13

39

Table 4-12: Base Wind Future Results – Load Sensitivities

High Load Low Load

Row Base Case Wind Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A










4.9.2 High Gas Future Sensitivity Analysis

The results in Table 4-13 indicate that for the Low Wind case, there are no unsolvable contingencies

(Row 3) in the EHV overlay. For the High Wind and SPP Import sensitivities, the results show several

unsolved contingencies (Row 3) for all three alternatives. The High Wind and SPP Import results

indicate the transmission network is stressed and is exceeding its capacity. The locations and magnitude

of new wind farms and gas generation facilities as well as load growth should be monitored as they could

have a significant impact on the results.

Table 4-13: High Gas Future Results – Generation Sensitivities High Wind Imports from SPP Low Wind


Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A










40

Table 4-14: High Gas Future Results – Load Sensitivities

High Load


Alt 5 Alt 5A

1 Overlay voltage violations: All facilities in-service 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0

3 Overlay unsolvable: Overlay N-1 1 0 0

4 Overlay thermal violations: Overlay N-1 0 0 0

5 Overlay voltage violations: Overlay N-1 2 3 3

6 Existing System Thermal violations: All facilities in-service 13 12 11

7 Existing System unsolvable: All N-1 18 17 19

8 Existing System thermal violations: Overlay N-1 2 3 7

9 Existing System thermal violations: Existing System N-1 90 98 134

4.9.3 Low Carbon Future Sensitivity Analysis

The High Wind and SPP Import sensitivities in the Low Carbon Future shown in Table 4-15 show

several unsolved contingencies (Row 3) for all three alternatives. These results are indicative of a

transmission network that is stressed and is exceeding its capability. The results indicate that there are no

unsolvable contingencies in the EHV overlay for the Low Wind case. The locations and magnitude of

new wind farms and coal plant retirements as well as load growth should be monitored as they could have

a significant impact on the results.

Table 4-15: Low Carbon Future Results – Generation Sensitivities

High Wind Imports from SPP Low Wind


Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A

Alt 2

Alt 5

Alt 5A










41

Table 4-16: Low Carbon Future Results – Load Sensitivities

High Load

Row Number of Violations Alt 2 Alt 5 Alt 5A

1 Overlay voltage violations: All facilities in-service 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0

3 Overlay unsolvable: Overlay N-1 0 0 1

4 Overlay thermal violations: Overlay N-1 0 0 0

5 Overlay voltage violations: Overlay N-1 3 3 3

6 Existing System Thermal violations: All facilities in-service 14 15 16

7 Existing System unsolvable: All N-1 12 13 14

8 Existing System thermal violations: Overlay N-1 10 5 14

9 Existing System thermal violations: Existing System N-1 197 160 191

5 Summary of Revised Alternatives

Based on the combined cost and performance analysis, three alternatives were selected for future

evaluation. Table 5-1 shows a high level summary of these optimized alternatives. Alternative 2 has

approximately 4,500 miles of 345 kV line and 4,000 miles of 765 kV line, while alternatives 5 and 5A

have approximately 7,800 and 7,000 miles of 765 kV line. While Alternative 5 does not consist of any

overhead HVDC line, Alternative 5A includes nearly 400 miles. Similarly Alternative 2 has

approximately the same number of new 345 kV and 765 kV buses, while Alternatives 5 and 5A only have

5 new 345 kV buses, but approximately 45 new 765 kV buses.

Table 5-2 applies the estimated component costs found in Table 4-4 to calculate an estimated cost for

each of the alternatives.

Table 5-1: High Level Summary of Revised Alternatives

High Level Summary Alt 2 Alt 5 Alt 5A

Number of 345 kV new Lines, single circuit. 5 0 0

Total Single Circuit miles 345 lines 245 0 0

Total Structure miles of 345 double circuit lines 4,409 80 80

Number of 765 kV new Lines, single circuit. 32 53 49

Total Circuit miles length of 765 lines 3,950 7,773 7,066

Number of 765/345 kV Transformers 21 40 40

Number of 230/345 kV Transformers 1 1 1

Number of River Crossing lines 5 8 8

HVDC Underwater Cable Circuit miles 64 91 91

HVDC Overhead Cable Circuit miles 200 0 385

Number of 345 kV new buses or connection to existing buses 34 5 5

Number of 765 kV new buses or connection to existing buses 32 46 44

42

Figure 5-1: Cost Estimates for Conceptual Alternatives

Element $M

Transmission Lines (includes right-of-way costs)


Double circuit 345 kV (USD / mile) 1.97


Transformers

345/230 kV, 500 MVA (USD / unit) 6.5

765/345 kV, 1000 MVA (USD / unit) 12.0

765/345 kV, 2250 MVA (USD / unit) 21.0

Network Stations (does not include land costs)



Major River crossings 7.0

HVDC Undersea Cable (USD / mile) 9.0

HVDC Overhead (USD /mile) 5.0

Reactive Correction

Shunt reactors (USD / MVAr) 0.0420

Table 5-2: Cost summary for Revised Alternatives

Line Costs in Millions of Dollars Alt 2 Alt 5 Alt 5A

Estimated Cost for 345 kV Lines $9,053 $158 $158

Estimated Cost for 765 kV Lines $10,705 $21,066 $19,149

Total Cost Transmission Lines $19,758 $21,224 $19,307

Transformers Costs

Estimated Cost of 765/345 kV Transformers $445 $848 $848

Estimated Cost of 230/345 kV Transformers $7 $7 $7

Total Costs Transformation $452 $855 $855

Network Substation/Station Costs 345 kV $472 $59 $59

Network Substation/Station Costs 765 kV $552 $879 $853

Total cost $1,024 $938 $912

River Crossing line costs $35 $56 $56

HVDC Costs $1,427 $1,281 $2,500

Shunt Reactors $1,115 $1,413 $1,205

Total Estimated Costs $23,811 $25,767 $24,835

6 Sequencing of Alternatives

6.1 Sequencing Approach

This section describes the SMARTransmission study sequencing approach as well as the results. The

goal of the sequencing approach was to determine the build out required in 2019 and 2024 that would

facilitate the development of the optimized 2029 transmission alternatives. The study sponsors first

defined optimal system alternatives for 2029. The 2029 alternatives were then used to develop

transmission the overlays for 2024 as described below.

43

1. Wind interconnection locations as shown in Figure 3-1 were not modified. Nameplate values

were reduced on a prorated basis for 2024 based on renewable energy requirements shown in

Table 6-2.

2. Based on these changes, lightly loaded lines were removed from 2029 revised EHV transmission

overlay alternatives.

3. Using an iterative process, the 2024 overlay alternatives were tested for N-1 contingencies to

ensure the reliability of the system.

4. The 2024 overlays were finalized based on the results from Step 3.

5. The 2024 overlay alternatives were tested for N-2 contingencies to evaluate the robustness of the

overlays.

The above process was repeated to create 2019 overlays from the final 2024 overlays. Several factors

could impact the results of the actual sequencing. Locations and magnitude of generation additions and

retirements as well as load growth should be monitored as they could have a significant impact on the

results.

6.2 Summary of RPS Values Used in Study

Table 6-1 shows the SMARTransmission assumptions for the RPS requirement by state for 2029, 2024,

and 2019. The highlighted values were taken from the Database of State Incentives for Renewable and

Efficiency website. Other values were extrapolated.

Table 6-1: RPS Requirements by State for Study Years 2029, 2024, 2019

Year IA IL IN MI MN MO ND NE OH SD WI Avg

2029 20.0% 25.0% 20.0% 20.0% 28.0% 20.0% 20.0% 20.0% 25.0% 20.0% 25.0% 22%

2024 15.0% 23.5% 15.0% 15.0% 25.0% 15.0% 16.0% 15.0% 25.0% 16.0% 24.0% 19%

2019 12.5% 16.0% 12.5% 12.5% 20.0% 12.5% 12.5% 12.5% 15.0% 12.5% 19.0% 14%

2015 10.0% 10.0% 10.0% 10.0% 15.0% 10.0% 10.0% 10.0% 5.0% 10.0% 13.0% 10%

The nameplate generation in Table 6-2 was calculated using the same methodology as the 2029 Base Case Wind in Section 2.1. Table 6-2: Nameplate Installed Wind Generation by State for Study Years 2029, 2024, 2019

Base Case Wind Low Wind High Wind

State 2029 2024 2019 2029 2024 2019 2029 2024 2019

IA 6,694 5,753 4,696 5,078 4,869 4,102 7,684 6,331 4,969

IL 7,919 6,774 4,486 5,026 4,774 3,466 10,198 8,641 5,446

IN 3,577 2,905 2,482 1,035 1,035 1,035 4,537 3,351 2,703

MI 8,201 5,852 4,640 3,519 3,466 3,415 10,186 6,919 5,222

MN 5,876 5,082 3,869 5,042 4,967 4,448 7,298 6,009 4,354

MO 3,070 2,357 1,555 1,845 1,686 1,104 3,821 2,795 1,762

ND 4,833 3,783 2,602 3,029 2,795 1,938 5,939 4,428 2,906

NE 5,196 3,893 2,429 2,958 2,668 1,606 6,567 4,693 2,806

OH 4,729 4,500 2,570 4,059 3,999 2,365 5,873 5,320 2,893

SD 4,208 3,196 2,057 2,469 2,243 1,417 5,274 3,818 2,351

WI 2,506 2,483 1,998 2,061 1,852 1,686 3,152 2,859 2,169

Total 56,809 46,579 33,384 36,121 34,355 26,582 70,528 55,164 37,581

44

6.3 2024 Sequencing of Alternatives

As discussed in Section 5.1, the 2029 revised EHV transmission overlay alternatives were used as a basis

for developing the 2024 overlays. For Alternative 5, the 765 kV line from Rockport (IN)-Kincaid (IL)-

Hills (IA)-Adair County (IA)-St Joseph (MO) was not required in 2024 because the Point Beach (WI) to

DC Cook (MI) HVDC line was chosen to meet the “theoretical cut set #4 transfer requirements. This

sequencing can be flexible based on the final needs and locational requirements for west to east transfers.

Since the HVDC line in Alternative 5A from Rockport to Adair County represents the same path,

Alternative 5A is identical to Alternative 5 for the 2024 sequence. As a result, there was no need to test

Alternatives 5 and 5A separately. The 2024 overlays for Alternatives 2 and 5 were tested for N-1

contingencies to ensure the reliability of the system. The 2024 sequence was also tested for High Wind,

Low Wind, SPP Imports, and High Load sensitivities. The results shown in Table 6-3 and Table 6-4

indicate that the alternatives perform adequately under the 2024 sequence.

Table 6-3: 2024 Base Wind Results for On and Off Peak Cases

Off Peak On Peak

Row Number of Violations Alt 2 Alt 5 Alt 2 Alt 5

1 Overlay voltage violations: All facilities in-service 0 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0

3 Overlay unsolvable: Overlay N-1 0 0 0 0

4 Overlay thermal violations: Overlay N-1 0 0 0 0

5 Overlay voltage violations: Overlay N-1 3 1 0 1

6 Existing System Thermal violations: All facilities in-service 3 11 0 0

7 Existing System unsolvable: All N-1 5 5 10 9

8 Existing System thermal violations: Overlay N-1 4 6 0 0

9 Existing System thermal violations: Existing System N-1 29 17 45 69

Table 6-4: 2024 Base Wind Results – Generation Sensitivities

Figure 6-1 shows 2024 sequencing for Alternative 2, the combination 345 kV and 765 kV alternative.

The dashed black lines represent the lines that were removed from the 2029 Alternative 2 topology.

High Wind SPP Imports Low Wind High Load

Row Number of Violations Alt 2 Alt 5 Alt 2 Alt 5 Alt 2 Alt 5 Alt 2 Alt 5

1 Overlay voltage violations: All facilities in-service 0 0 0 0 0 0 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0 0 0 0 0

3 Overlay unsolvable: Overlay N-1 11 4 1 2 0 0 0 0

4 Overlay thermal violations: Overlay N-1 0 2 0 0 0 0 0 0

5 Overlay voltage violations: Overlay N-1 9 3 1 0 4 29 0 0

6 Existing System Thermal violations: All facilities in-service 10 6 7 5 2 3 0 0

7 Existing System unsolvable: All N-1 6 4 3 3 2 3 13 15

8 Existing System thermal violations: Overlay N-1 17 28 1 18 0 1 0 0

9 Existing System thermal violations: Existing System N-1 198 90 31 22 13 9 86 83

45

Figure 6-1: Alternative 2 Showing Lines to be Removed for 2024 Revised EHV Transmission Overlay

46

Figure 6-2 shows 2024 sequencing for Alternative 5, the 765 kV-only alternative. The dashed black lines

represent the lines that were removed from the 2029 Alternative 5 topology.

Figure 6-2: Alternative 5 Showing Lines to be Removed for 2024 Revised EHV Transmission Overlay

6.3.1 2024 Double Contingency Analysis

Double contingency (N-2) analysis was performed on the 2024 off peak model. The sponsor group chose

off peak models to perform the analysis since off peak periods are characterized by high wind generation,

low consumer loads, and heavily loaded EHV facilities. The double contingencies were simulated on the

revised EHV transmission overlay and existing 765 kV elements. Using generation re-dispatch, N-1-1

contingency analysis was simulated for those N-2 contingencies that resulted in non-convergent solutions.

Approximately 2.4 GW of generation was curtailed in North and South Dakota for the outages of

Hankinson (ND) to Helena (MN) and New Sub MN1 (MN) to Helena (MN) 765 kV lines in Alternative

2. Similarly, approximately 1.3 GW of generation was re-dispatched in North Dakota, Minnesota and

Iowa for Bison (ND) to Helena (MN) and Bison (MN) to Chisago County (MN) 765 kV line outages in

Alternative 5. Numerous non-solving contingencies were noted on the existing system. These are

expected to be addressed by generation re-dispatch and should be further evaluated for feasibility in

planning studies.

47

6.4 2019 Sequencing of Alternatives

As discussed in Section 5.1, the 2024 revised EHV transmission overlay alternatives were used as a basis

for developing the 2019 overlays. The 2019 overlays were tested for N-1 contingencies to ensure the

reliability of the system. The 2019 sequence was also tested for High Wind, Low Wind, SPP Imports,

and High Load sensitivities. The results shown in Table 6-5 and Table 6-6 indicate that the alternatives

perform adequately under the 2019 sequence.

Table 6-5: 2019 Base Wind Results for On and Off peak Cases

Table 6-6: 2019 Base Wind Results – Generation Sensitivities

Off Peak On Peak Row Number of Violations Alt 2 Alt 5 Alt 2 Alt 5

1 Overlay voltage violations: All facilities in-service 0 1 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0

3 Overlay unsolvable: Overlay N-1 0 0 0 0

4 Overlay thermal violations: Overlay N-1 0 0 0 0

5 Overlay voltage violations: Overlay N-1 4 0 0 0

6 Existing System Thermal violations: All facilities in-service 2 2 0 0

7 Existing System unsolvable: All N-1 3 3 5 5

8 Existing System thermal violations: Overlay N-1 5 20 0 0

9 Existing System thermal violations: Existing System N-1 34 13 31 44

High Wind SPP Imports Low Wind High Load Row Number of Violations Alt 2 Alt 5 Alt 2 Alt 5 Alt 2 Alt 5 Alt 2 Alt 5

1 Overlay voltage violations: All facilities in-service 0 0 0 1 0 1 0 0

2 Overlay thermal violations: All facilities in-service 0 0 0 0 0 0 0 0

3 Overlay unsolvable: Overlay N-1 1 4 0 1 0 0 0 0

4 Overlay thermal violations: Overlay N-1 1 2 0 0 0 0 0 0

5 Overlay voltage violations: Overlay N-1 3 4 3 1 7 0 0 0

6 Existing System Thermal violations: All facilities in-service 2 3 2 2 2 0 0 0

7 Existing System unsolvable: All N-1 4 7 4 5 3 2 38 39

8 Existing System thermal violations: Overlay N-1 0 2 4 7 0 1 1 4

9 Existing System thermal violations: Existing System N-1 11 21 30 17 16 15 57 78

48

Figure 6-3 shows 2019 sequencing for Alternative 2, the combination 345 kV and 765 kV alternative.

The dashed black lines represent transmission lines that were removed from the 2024 Alternative 2

topology.

Figure 6-3: Alternative 2 Showing Lines to be Removed for the 2019 Revised EHV Transmission Overlay

49

Figure 6-4 shows 2019 sequencing for Alternative 5, the 765 kV-only alternative. The dashed black lines represent the lines that were removed from the 2024 Alternative 5 topology. Figure 6-4: Alternative 2 Showing Lines to be Removed for the 2019 Revised EHV Transmission Overlay

6.4.1 Double Contingency Analysis

Double contingency (N-2) analysis was performed on the 2019 off peak model. The sponsor group chose

off peak models to perform the analysis since off peak periods are characterized by high wind generation,

low consumer loads, and heavily loaded EHV facilities. The double contingencies were simulated on the

revised EHV transmission overlays and the existing 765 kV elements. Using generation re-dispatch, N-1-

1 contingency analysis was simulated for those N-2 contingencies that resulted in non-convergent

solutions. For example, approximately 1.4 GW of generation was curtailed in North and South Dakota

for the Hankinson (ND) to Helena (MN) and New Sub MN1 (MN) to Helena (MN) 765 kV line outages

in Alternative 2 to obtain a convergent solution. Similarly, approximately 1.5 GW of generation had to be

re-dispatched in North and South Dakota for the Bison (ND) to Helena (MN) and Bison (ND) to Chisago

County (MN) 765 kV line outages in Alternative 5. Numerous reliability issues associated with N-2

analysis were seen on the existing system. These are expected to be addressed by generation re-dispatch

and should be further evaluated for feasibility in planning studies.

50

7 Phase 2: Economic Benefits Evaluation

Phase 2 will be used to study the economic benefits of the revised EHV transmission overlay

Alternatives. The work will compare the revised alternatives and rank them by performance. PROMOD

by Ventyx will be used as the security constrained economic dispatch software, and the 2019 Regional

Generation Outlet Study (RGOS) production model developed by MISO will be used as the starting point

to build the SMARTransmission production models.

Phase 2 metrics that will be studied include:

• The Adjusted Production Cost (APC) is a measure of the impact on production cost by nodal

LMPs, accounting for purchases and sales of economic energy interchange. This metric is

typically simulated by a production cost modeling tool accounting for 8,760 hourly profiles per

year of commitment and dispatch modeling, taken over the course of the study period.

• The Environmental Costs include SO2, NOX, and CO2. The pricing for SO2 and NOX is

approximated using data from the RGOS model which represents our best estimate of current

market prices.

• Load Cost is also referred to as load payment. It is the zonal LMP based total energy cost to

consumers. Hourly load-weighted average LMP price for each zone is calculated and multiplied

with the zonal load to determine the hourly zonal load payment. The zonal annual load payment

is then the sum of all 8760 hourly load payments.

• The Annual Project Cost is calculated on zonal level as follows:

Annual Project Cost = 70% * Annual APC + 30% * Annual Load Cost

The 70% APC / 30% Load Cost calculation is consistent with the Midwest ISO’s economic

analysis process and represents a rough approximation of the percentage of the study footprint

under regulated retail rates (70%) and the percentage of the study footprint with a deregulated

retail market (30%).

8 Conclusion

Transmission infrastructure is critical to the interconnection and delivery of energy. SMARTransmission

seeks to ensure that the system is efficient and capable of interconnecting wind and other generation

resources. The revised EHV transmission overlay alternatives developed in Phase 1 are designed to

reliably and efficiently integrate 56.8 GW of wind energy in the Midwest and help states to satisfy

renewable energy standards and goals.

Throughout the study, the SMARTransmission sponsors have shared the results with the Midwest

Independent Transmission System Operator, PJM Interconnection and Southwest Power Pool to serve as

input to their regional transmission planning processes. These Regional Transmission Organizations will

make the final decisions with regard to the scope and timing of transmission projects and will identify

required projects.

51

Contingency analysis performed as part of Phase 1 indicates that revised Alternative 2 and Alternative 5

performed adequately with all transmission facilities in service and single contingency conditions for the

base wind model (56.8 GW). While some N-1 violations were identified on the underlying system, those

violations are generally a function of load growth and wind resource locations. Violations on the

underlying system for N-2 contingencies are expected to be addressed with re-dispatch and local planning

upgrades. Planning studies will be required to determine the upgrades needed to integrate a transmission

overlay into existing systems. While these revised alternatives demonstrated improved performance over

the other conceptual designs considered in the first phase of the study, the projects included in these

alternatives do not preclude different long-range projects that accomplish similar system performance to

the projects in these alternatives.

To identify a potential build out for 2019 and 2024, the sponsor team developed a sequencing approach

for each of the revised EHV transmission overlay alternatives. The sequencing was designed to help

prioritize projects in order to efficiently develop the 2029 transmission alternatives. Locations and

magnitude of generation additions and retirements, as well as load growth, should be monitored as they

could have a significant impact on the direction of the actual sequencing. The phasing alternatives do not

preclude alternative phasing and short-range projects that accomplish similar system performance.

The SMART study analyzed transmission system needs from a regional perspective over a study area that

encompasses some of the country’s best wind resources. The information derived from this analysis is

being used to recommend an EHV transmission overlay solution that can be integrated with the existing

transmission system in areas of North and South Dakota, Iowa, Indiana, Ohio, Illinois, Michigan,

Minnesota, Nebraska, Missouri and Wisconsin. The full scope of benefits expected from the EHV

transmission overlay alternatives will be evaluated in Phase 2.

52

A Appendix A: Key Assumptions

A.1 Study Area The SMARTransmission Study focuses on areas within North and South Dakota, Iowa, Indiana, Ohio,

Illinois, Minnesota, Missouri, Nebraska, Michigan, and Wisconsin as shown within the demarcated line in

Figure A- 1. The Study area is spread across three Regional Transmission Organizations (RTOs) –

Midwest ISO, PJM and SPP.

Figure A- 1: SMARTransmission Study Area

53

The 36 control areas included in the Study area are listed in Table A - 1.

Table A - 1: Control Areas and Associated Codes and Numbers

Ref RTO Planning Region

Area Code Area Name Area

#

1 Midwest ISO West ALTW Alliant Energy West 627

2 ALTE Alliant Energy East 694

3 WEC Wisconsin Energy Corporation 295

4 WPS Wisconsin Public Service Corporation 696

5 MGE Madison Gas & Electric 697

6 UPPC Upper Peninsula Power Co. 698

7 XEL Excel Energy Services Inc. 600

8 DPC Dairyland Power Cooperative 680

9 MP Minnesota Power, Inc 608

10 SMMPA Southern MN Municipal Power Association 613

11 GRE Great River Energy 615

12 OTP Otter Tail Power Company 620

13

MDU (in WAPA) Montana-Dakota Utilities 661

14 Central HE Hoosier Energy Rural Electric 207

15 DEM Duke Energy Midwest (Cinergy) 208

16 Vectren Vectren (Southern Indiana Gas & Electric) 210

17 IP&L Indianapolis Power & Light 216

18 CWLD Columbia Water and Light 333

19 AmerenMO Ameren MO 356

20 AmerenIL Ameren IL 357

21 CWLP City Water Light & Power 360

22 SIPC Southern Illinois Power Cooperative 361

23 MPW Muscatine Power & Water 633

24 MEC MidAmerican Energy Company 635

25 East FE First Energy 202

26 NIPSCo Northern Indiana Public Service Company 217

27 METC Michigan Electric Transmission Company 218

28 ITC International Transmission Company 219

29 PJM CE Commonwealth Edison (ComEd) 222

30 AEP American Electric Power 205

31 DAY Dayton Power and Light 209

32 SPP NPPD Nebraska Public Power District 640

33 OPPD Omaha Public Power District 645

34 LES Lincoln Electric System 650

35 N/A OVEC Ohio Valley Electric Corporation 206

36 WAPA Western Area power Administration 652

54

A.2 Time frame The Study seeks to assess transmission system needs in 2029. After the 2029 EHV Overlay alternatives

were defined, transmission upgrade requirements for 2019 and 2024 were developed. This sequencing

process was used to facilitate an efficient build out of the transmission overlay in an effort to preclude the

development of a piecemeal transmission system that only considers immediate needs.

A.3 2029 Energy Requirements Energy usage by state was obtained from the EIA website for 1990-2007. For each state in the study area,

(except Wisconsin which used 1.1%), usage was inflated by 1.0% annually through 2029. Table A - 2

calculates the total 2029 energy requirements for the study area and the amount of that energy that will be

supplied by wind generation based on the RPS considered for the states. The basis for the information

provided in the table is explained in Section 3.1.1 of the main report.

Table A - 2: Energy Required by State for Base Wind 2029

IA IL IN MI MN MO ND NE OH SD WI

Federal 20% - State RPS - Utility RPS in %

20% 25% 20% 20% 28% 20% 20% 20% 25% 20% 25%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%

Average Capacity Factor (Supplied from MISO 3 Year Capacity Factor Statistics

0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3

High Wind State- yes/no? (high wind state if capacity factor >36%)




45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


56,347,693 181,797,163 136,196,996 136,043,397 84,928,434 106,464,095 14,819,207 35,161,231 201,358,714 13,198,097 90,703,255

% for RPS renewable (MWh) - 11,269,539 45,449,291 27,239,399 27,208,679 23,355,319 21,292,819 2,963,841 7,032,246 50,339,679 2,639,619 22,675,814


Total 172,397,256

A.4 2029 Wind Nameplate Values Table A - 3 shows wind generation levels that would allow states to meet Federal and state RPS requirements. The generation is based on state

wind capacities developed by NREL and in-state wind requirements. An iterative process was used to determine the excess wind generation within

each state that could be exported to states that did not have adequate in-state wind resources to fulfill their RPS requirements. A detailed

explanation is provided in Section 3.1.2 of the main report.

Table A - 3: Total Wind by State for Base Wind 2029

A B C D E F G H I J

Energy to meet ~80%

RPS Requirement

Existing Wind as of May

2009


Requirement

Incremental Wind

Prorate of NREL by

State

Energy (Import) / Export by

State

% RPS Wind

Generated In-State

Incremental Wind

Prorate of NREL by

State

Energy (Import) / Export by State

Total Wind by State


State MWh MWh (B-C) MWh MWh

(E-D) MWh % MW MW MW

IA 9,015,631 10,109,338 (1,093,707) 12,055,001 13,148,708 100% 3,641 3,857 6,694

IL 34,086,968 4,441,320 29,645,648 16,370,614 (13,275,034) 61% 6,229 (3,894) 7,919

IN 21,791,519 2,946,645 18,844,874 7,238,053 (11,606,822) 47% 2,542 (3,404) 3,577

MI 21,766,944 342,402 21,424,541 21,424,541 0 100% 8,072 0 8,201

MN 18,684,256 5,739,683 12,944,572 12,944,572 0 100% 4,071 0 5,876

MO 17,034,255 958,221 16,076,034 8,562,158 (7,513,876) 56% 2,761 (2,204) 3,070

ND 2,371,073 2,674,130 (303,057) 14,176,611 14,479,667 100% 4,066 4,247 4,833

NE 5,625,797 540,133 5,085,664 17,801,633 12,715,968 100% 5,043 3,730 5,196

OH 25,169,839 18,641 25,151,198 12,575,599 (12,575,599) 50% 4,722 (3,689) 4,729

SD 2,111,696 1,019,244 1,092,452 13,873,332 12,780,880 100% 3,920 3,749 4,208

WI 14,739,279 1,500,588 13,238,691 5,084,796 (8,153,895) 45% 1,935 (2,392) 2,506

Total 172,397,256 30,290,346 142,106,911 142,106,911 47,002 0 56,809

57

A.5 Wind Energy Contribution by Wind Farms Wind is an intermittent resource, and wind generation often has limited availability during peak hours

when the load is at its highest. To account for this generation profile, the study assumes a wind

contribution of 20% of the installed nameplate capacity for the summer peak case. Wind farms generally

produce more energy during off peak hours than on peak hours. The Study assumed a wind contribution

of 90% during those hours.

A.6 Power Flow Cases As shown in Figure A-1, the majority of the study area is within the Midwest ISO’s footprint. As a result,

the Midwest ISO’s Transmission Expansion Plan (MTEP) 2019 summer peak model was used as a

starting point to develop summer peak cases for 2029, 2024 and 2019. The Midwest ISO power flow

models are updated annually to provide current transmission system topology. Midwest ISO’s models

also depict neighboring transmission systems in detail.

A Midwest ISO 2019 off peak case was used to develop off peak models for 2029, 2024 and 2019. The

off peak cases model loads at 70% of summer peak load conditions.

A.7 Load Forecasts Load projection rates were based on Midwest ISO10 and PJM11 forecasts. Growth rates ranged

from 0.85% to 1.4% and are listed by control area in Table A - 4. These values were applied to

the Midwest ISO 2019 models to develop the 2029 models. Major industrial loads for 2029 were

not increased from their 2019 levels. This methodology resulted in a demand increase of

approximately 30 GW for the 10-year period from 2019 through 2029.

10 Based on Midwest ISO 2008 Load Forecasts, the calculated average annual load growth rate is approximately 1.4% from 2008 to 2017. 11 The PJM 2008 Load Forecasts projects the peak to grow at 1.4% for the next 15 years

(PJM 2008 Regional Transmission Expansion Plan).

58

Table A - 4: Estimated Annual Load Growth by Control Areas

Ref Area No

Area Code

Yearly Load Growth

1 205 AEP 0.85%

2 600 XEL 1.0%

3 608 MP 1.0%

4 613 SMMPA 1.0%

5 615 GRE 1.0%

6 620 OTP 1.0%

7 627 ALTW 1.0%

8 633 MPW 1.0%

9 635 MEC 1.0%

10 640 NPPD 1.0%

11 645 OPPD 1.0%

12 650 LES 1.0%

13 652 WAPA 1.0%

14 661 MDU 1.0%

15 680 DPC 1.0%

16 694 ALTE 1.4%

17 357 AMIL 1.4%

18 356 AMMO 1.4%

19 222 CE 1.4%

20 333 CWLD 1.4%

21 360 CWLP 1.4%

22 209 DAY 1.4%

23 208 DEM 1.4%

24 202 FE 1.4%

25 207 HE 1.4%

26 216 IPL 1.4%

27 219 ITCT 1.4%

28 218 METC 1.4%

29 697 MGE 1.4%

30 217 NIPS 1.4%

31 206 OVEC 1.4%

32 210 SIGE 1.4%

33 361 SIPC 1.4%

34 698 UPPC 1.4%

35 295 WEC 1.4%

36 696 WPS 1.4%

59

A.8 Generation Retirements All generating units were dispatched in the base cases. In the low carbon future scenario, coal units that

were over 40 years old in 2010 and had a maximum capacity of 250 MW were assumed to be retired.

Coal plant information is available on the EIA website12.

A.9 Future Proxy Non-wind Generation New generation resources were needed to meet the assumed 2029 demand increases. The following

methodology was used to determine non-wind generation by state:

• The load of approximately 30 GW was increased from 2019 through 2029.

• Generation was added in the study area to meet the total incremental load of approximately 30

GW.

• Twenty percent of the 56.8 GW of wind generation (as calculated in Table 3-3) amounts to

approximately 11.4 GW was added in the peak load base case.

• The remaining generation of 18.6 GW required to meet the 2029 load requirement was achieved

through 18.3 GW of non-wind resources (see Table A - 5) and the deficit of 0.3 GW was handled

by the slack busses in the system.

12 www.eia.doe.gov

60

Table A - 5: Non-Wind Resources

State / Area Bus No. Bus Name Pmax Fuel type

AEP-OH AEP-OH 243208 05JEFRSO 600 Proxy unit

AEP-OH AEP-OH 248000 06CLIFTY 1200 Proxy unit

AEP-OH AEP-OH 242935 05E LIMA 600 Proxy unit

IA _ALTW 631139 HAZLTON3 600 ST Coal

IA _MEC 635680 BONDRNT3 600 ST Coal

IA _MEC 635630 BOONVIL3 184 CT Gas

IL _AMIL 347850 7NORRIS 600 ST Coal

IL _AMIL 348747 7BROKAW T2 600 CT Gas

IL _AMIL 347962 7PAWNEE 450 CT Gas

MI _METC 256196 18LTSRDJ 600 ST Coal

MI _METC 256143 18FILRCT 120 ST Coal

MN XEL 601011 SHERCO 3 600 ST Coal

MN XEL 601011 SHERCO 3 600 ST Coal

MN XEL 601001 FORBES 2 126 ST Coal

MN _GRE 619975

GRE-

WILLMAR4 450 Proxy unit

MO _AMMO 345669 7RUSH 600 CT Gas

NE _OPPD 645740 S3740 3 138 CT Gas

OH _DEM 249522 08VERM M 600 CT Gas

OH _DEM 249508 08DRESSR 600 CT Gas

OH _DEM 249501 08BATESV 600 ST Coal

OH _FE 238961 02MIDWAY 600 CT Gas

OH _FE 238569 02BEAVER 600 CT Gas

OH _FE 239092 02SAMMIS 600 ST Coal

SD SDND 652519 OAHE 4 372 ST Coal

WI _MGE 699157 COL 345 140 ST Coal

WI _MGE 698928 WERNER W 600 Proxy Unit

WI _MGE 699359 N APPLETO 600 Proxy Unit

WI _WPS 699785 ROCKY RN 600 CT Gas

IN DEM 249508 08DRESSR 600 CT Gas

OH-IN AEP 242605 05CLNCHR 534 Coal

OH-IN AEP 940300

Spor-Water

Tap 1200 IGCC

OH-IN AEP 242940 05MUSKNG 600 Coal

IN NIPS 255108 17MCHCTY 600 ST Coal

MO AMMO 346004 GOSCKMO1 210 CT Gas

18324

61

A.10 Reactive Load Support Power system capacitors were added in 2029 to maintain system voltages within adequate limits (Table A

- 6).

Table A - 6: Voltage Performance Criteria for Transmission Facilities 200 kV and Above

Normal operation

Min Max

ComEd 98% 103%

AEP 95% 105%

Remaining Control Areas 95% 105%

A.11 Generation Dispatch To accommodate off peak wind generation, the output of the existing units was reduced. The following

criteria were applied to the generation of the existing non-wind units:

• The dispatch of nuclear units was maintained at 100%.

• Coal units were reduced in proportion to their nameplate capacities to accommodate wind

generation. Units were not reduced below their minimum required levels.

• Gas units were turned off.

• Units critical for voltage, reliability or transmission system stability were kept on-line.

A.12 Power Exports An important premise of the SMART Study is that the energy available from 56.8 GW of wind generation

is adequate to meet the RPS requirements of the study area. For on peak load levels there is no wind

energy exports outside the study area. However, during off peak periods some of the wind generation will

be in excess of the study area load requirements. This scenario was simulated by transferring the excess

wind generation to load sinks that were created along the eastern border of the study area.

A.13 Transmission Overlay Assumptions The following assumptions were used to develop the alternatives:

• For 765 kV lines, only single circuits were considered.

• No more than two 345 kV double circuits were considered in the same right-of-way. In

practice, the double circuit lines may traverse different right-of-ways. For ease of use

they are shown sharing the same right-of-ways.

• Table A - 7 shows conductor assumptions and line capabilities based on surge impedance

loading:

62

Table A - 7: Surge Impedance Loading Reference

Nominal Voltage 345 kV 2-345 kV 500 kV 765 kV Number and Size of Conductors per phase

2x954 2x954* 3x954 6x795

Surge Impedance Loading (MW)

390 780 910 2380

Line Length (miles)

Line Loading (SIL)

Loadability in MW (No Compensation)

50 3.0 1170 2340 2730 7140

100 2.0 780 1560 1820 4760

150 1.6 630 1250 1460 3810

200 1.3 510 1010 1180 3090

250 1.1 430 860 1000 2620

300 1.0 390 780 910 2380

* Other conductors are used by different transmission owners and the SIL would change less than 5%.

A.14 Thermal and Voltage Performance Criteria Steady State load flow analysis included a single contingency analysis (N-1) of transmission facilities in

the study area that have nominal voltages of 345 kV or above. Double contingency analysis (N-2) was

performed on select facilities identified to be critical to the Study. Transmission facilities with nominal

voltages of 200 kV or above were monitored for thermal and voltage violations.

Under normal conditions, with all transmission facilities in service, system elements with thermal

loadings over 100% of their normal ratings were reported as violations. In general, facility emergency

ratings were the threshold for reporting violations following single and double contingencies in the

monitored control areas. AEP differs in its criteria when evaluating EHV facilities following single

contingencies by requiring that the facility normal ratings are not exceeded.

Table A - 8 shows the voltage performance criteria used for facilities rated 200 kV and above.

Table A - 8: Voltage Performance Criteria for Transmission Facilities 200 kV and Above

Normal operation Contingency Min Max Min Max

ComEd 98% 103% 95% 105%

AEP 95% 105% 90% 105%

Remaining Control Areas 95% 105% 90% 110%

A.15 Performance Metrics Each of the eight alternatives was evaluated against a predetermined set of metrics with the goal of

choosing the alternatives that would provide reliable service to customers while considering both cost and

63

the impact on the environment. The evaluation criteria included reliability assessment, total cost,

transmission circuit miles13, major river crossings, the number of new substations, system losses14, and the

number of new lines.15 Based on the metrics, five alternatives were eliminated from further study.

A.16 Futures and Sensitivities The assumptions detailed above were used to develop and analyze the 2029 base cases. Two other future

scenarios were considered to capture the uncertainties associated with future economic and political

conditions. Futures analysis was performed on Alternatives 2, 5 and 5A. To test the robustness of the

alternatives, additional sensitivities, including High and Low Load Growth,

High and Low wind generation, and SPP Imports were also conducted on certain base and futures cases.

A detailed description of the futures and sensitivities is provided in Appendix B. The following sections

provide information on the assumptions and wind calculations for the high and low wind generation

sensitivities.

A.16.1 High Wind Generation Assumptions • Wind energy requirements were based on the RPS assumptions shown in Table 3-1 of the

main report. A 20% Federal mandate was used as a starting point, and requirements were

increased if state or utility mandates were higher.

• Power demand was assumed to be the same; however, energy growth was increased from

1.0% to 2.0% to calculate states’ 2029 renewable energy requirements (Table A - 9).

The process used to determine the wind nameplate capacity by state was similar to that used for the base

cases (Table 3-4 in the main report

13

Circuit miles are a key driver of total cost. They were used as a proxy to assess land owner issues. 14 The impact of the overlay on the required generation resources. 15 Number of Lines were used as a proxy to assess community concerns.

Table A - 9: RPS Requirement by State for High Wind in 2029 State IA IL IN MI MN MO ND NE OH SD WI


20% 25% 20% 20% 28% 20% 20% 20% 25% 20% 25%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%

Average Capacity Factor (Supplied from Midwest ISO 3 Year Capacity Factor Statistics

0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3

High Wind State- yes/no? (High wind state if CF>36%)




45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300

Total energy usage extrapolated assuming constant growth (MWh) (2029)

69,985,762 225,798,294 169,161,327 168,970,552 105,484,020 132,232,047 18,405,962 43,671,452 250,094,410 16,392,488 110,230,360

% for RPS renewable (MWh) 13,997,152 56,449,574 33,832,265 33,794,110 29,008,106 26,446,409 3,681,192 8,734,290 62,523,602 3,278,498 27,557,590


Total 213,729,034

Table A - 10: Total Wind Capacity by State for High Wind in 2029

A B C D E F G H I J

Energy to meet ~80% RPS Requirement

Existing Wind


Incremental Wind Prorate of NREL by State

Energy Import/Export by State

% RPS Wind Energy Generated In State


Import / Export by State

Total Wind by

State Existing

+ Increme

ntal

State MWh MWh (B-C) MWh MWh (E-D) MWh % MW MW MW

IA 11,197,722 10,109,338 1,088,384 15,333,335 14,244,951 100% 4,631 4,178 7,684

IL 42,337,180 4,441,320 37,895,860 22,358,558 (15,537,303) 63% 8,508 (4,557) 10,198

IN 27,065,812 2,946,645 24,119,167 9,970,020 (14,149,148) 48% 3,502 (4,150) 4,537

MI 27,035,288 342,402 26,692,886 26,692,886 0 100% 10,057 0 10,186

MN 23,206,484 5,739,683 17,466,801 17,466,801 0 100% 5,493 0 7,298

MO 21,157,128 958,221 20,198,906 10,890,620 (9,308,286) 56% 3,512 (2,730) 3,821

ND 2,944,954 2,674,130 270,824 18,031,912 17,761,088 100% 5,172 5,209 5,939

NE 6,987,432 540,133 6,447,300 22,642,752 16,195,452 100% 6,414 4,750 6,567

OH 31,261,801 18,641 31,243,160 15,621,580 (15,621,580) 50% 5,866 (4,582) 5,873

SD 2,622,798 1,019,244 1,603,555 17,646,158 16,042,603 100% 4,986 4,705 5,274

WI 17,912,434 1,500,588 16,411,846 6,784,083 (9,627,763) 46% 2,581 (2,824) 3,152

213,729,034 30,290,346 183,438,689 183,438,703 60,721 0 70,528

A.16.2 2029 Low Wind Assumptions:

• Wind energy requirements were based on existing RPS mandates and goals shown in Table 3-1 of the main report.

• Power demand was assumed to be the same; however, energy growth was reduced from 1.0% to 0.3% to calculate states’ 2029 renewable

energy requirements. This is shown in Table A - 11.

• The methodology used to determine the wind nameplate capacity by state was similar to that used for the base case (Table 3-4). Results are

shown in Table A - 12.

Table A - 11: State RPS Energy Requirements for Low Wind in 2029

State IA IL IN MI MN MO ND NE OH SD WI

State RPS Only 2% 23% 0% 10% 28% 15% 10% 15% 25% 10% 24%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%


0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3





45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


47,634,519 153,685,445 115,136,538 115,006,690 71,795,753 90,001,305 12,527,679 29,724,169 170,222,148 11,157,245 75,026,262

% for RPS renewable (MWh) 952,690 35,347,652 0 11,500,669 19,743,832 13,500,196 1,252,768 4,458,625 42,555,537 1,115,724 18,006,303

RPS energy from wind (MWh) 762,152 26,510,739 0 9,200,535 15,795,066 10,800,157 1,002,214 3,566,900 21,277,769 892,580 11,704,097

Total 101,512,209

Table A - 12: Total Wind by State for Low Wind 2029

A B C D E F G H I J

Energy to meet ~80% RPS Requirement

Existing Wind






Import/Export by State

Total Wind by State Existing + Incremental


IA 773,653 10,109,338 -9,335,684 6,706,604 16,042,289 100% 2,025 4,705 5,078

IL 29,250,863 4,441,320 24,809,543 8,767,692 -16,041,850 45% 3,336 -4,705 5,026

IN 0 2,946,645 0 0 0 0 0 1,035

MI 9,339,374 342,402 8,996,972 8,996,972 0 100% 3,390 0 3,519

MN 16,033,418 5,739,683 10,293,734 10,293,734 0 100% 3,237 0 5,042

MO 10,963,134 958,221 10,004,912 4,763,417 -5,241,495 52% 1,536 -1,537 1,845

ND 1,017,338 2,674,130 -1,656,792 7,886,927 9,543,719 100% 2,262 2,799 3,029

NE 4,827,634 540,133 4,287,501 9,903,649 5,616,148 100% 2,805 1,647 2,958

OH 21,598,856 18,641 21,580,215 10,790,107 -10,790,107 50% 4,052 -3,165 4,059

SD 906,049 1,019,244 -113,195 7,718,203 7,831,398 100% 2,181 2,297 2,469

WI 12,375,745 1,500,588 10,875,157 3,915,056 -6,960,100 44% 1,490 -2,041 2,061

107,086,063 30,290,346 79,742,362 79,742,362 26,314 0 36,121

A.17 Sequencing of Alternatives The SMARTransmission Study seeks to assess the 2029 transmission system required to accommodate the integration of 56.8 GW of wind generation.

After the 2029 EHV overlay alternatives were defined, the transmission upgrades required for 2019 and 2024 were developed. The overlay alternatives

were optimized and then their construction sequences were developed. This sequencing process was used to facilitate an efficient build out of the

transmission overlay in an effort to preclude the development of a piecemeal transmission system that only considers immediate needs. The

intermediate transmission system plans were also sensitivity tested for low and high wind, SPP Imports, and higher than forecasted load growth. Table

A - 13 shows the SMARTransmission assumptions for the RPS requirement by state for 2029, 2024, and 2019. The highlighted values were taken from

the state RPS information referenced in Section 3.1.1 of the main report. Other values were extrapolated.

Table A - 13: RPS Requirements by State for Study Years 2029, 2024, 2019

Year IA IL IN MI MN MO ND NE OH SD WI Average

2029 20% 25% 20% 20% 28% 20% 20% 20% 25% 20% 25% 22%

2024 15% 23.5% 15% 15% 25% 15% 16% 15% 25% 16% 24% 18%

2019 12.5% 16% 12.5% 12.5% 20% 12.5% 12.5% 12.5% 15% 12.5% 19% 14%

2015 10% 10% 10% 10% 15% 10% 10% 10% 5% 10% 13% 10%

Year IA IL IN MI MN MO ND NE OH SD WI Average

2029 20% 25% 20% 20% 28% 20% 20% 20% 25% 20% 25% 22%

2024 15% 23.5% 15% 15% 25% 15% 16% 15% 25% 16% 24% 18%

2019 12.5% 16% 12.5% 12.5% 20% 12.5% 12.5% 12.5% 15% 12.5% 19% 14%

2015 10% 10% 10% 10% 15% 10% 10% 10% 5% 10% 13% 10%

A.17.1 2024 Base Wind Assumptions

• Wind energy requirements were based on the RPS assumptions shown in Table A - 13.

• For each state in the study area, (except Wisconsin which used 1.1%), usage was inflated by 1.0% annually through 2024. State renewable

energy requirements are shown in Table A - 14.

• The 2024 wind nameplate capacity by state was calculated using the same methodology as used for the 2029 base case (shown in Table 3-4 in

the main report). The results are shown in Table A - 15.

Table A - 14: RPS Energy Requirement by State for Base Wind 2024


Federal 20% - State RPS - Utility RPS in % 15.0% 23.5% 15.0% 15.0% 25.0% 15.0% 15.0% 15.0% 25.0% 15.0% 24.0%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%


0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3





45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


53,612,897 172,973,763 129,586,769 129,440,624 80,806,491 101,296,933 14,099,967 33,454,705 191,585,907 12,557,536 85,875,068


RPS energy from wind (MWh)

6,433,548 30,486,626 15,550,412 15,532,875 16,161,298 12,155,632 1,691,996 4,014,565 23,948,238 1,506,904 13,396,511

Total 140,878,605


A B C D E F G H I J

Energy to meet

~80% RPS Requirement

Existing Wind


Incremental Wind

Prorate of NREL

by State

Energy Import/Expor

t by State

% RPS Wind Energy

Generated In State

Incremental Wind

Prorate of NREL

by State

Import/Export

by State

Total Wind by State



IA 6,433,548 10,109,338 -3,675,790 8,941,129 12,616,919 100% 2,700 3,701 5,753

IL 30,486,626 4,441,320 26,045,306 13,361,242 -12,684,064 58% 5,084 -3,720 6,774

IN 15,550,412 2,946,645 12,603,767 5,324,966 -7,278,802 53% 1,870 -2,135 2,905

MI 15,532,875 342,402 15,190,473 15,190,473 0 100% 5,723 0 5,852

MN 16,161,298 5,739,683 10,421,615 10,421,615 0 100% 3,277 0 5,082

MO 12,155,632 958,221 11,197,411 6,350,506 -4,846,905 60% 2,048 -1,422 2,357

ND 1,691,996 2,674,130 -982,134 10,514,715 11,496,849 100% 3,016 3,372 3,783

NE 4,014,565 540,133 3,474,432 13,203,374 9,728,942 100% 3,740 2,854 3,893

OH 23,948,238 18,641 23,929,597 11,964,799 -11,964,799 50% 4,493 -3,509 4,500

SD 1,506,904 1,019,244 487,661 10,289,775 9,802,114 100% 2,908 2,875 3,196

WI 13,396,511 1,500,588 11,895,923 5,025,908 -6,870,014 49% 1,912 -2,015 2,483

140,878,605 30,290,346 110,588,259 110,588,499 36,772 0 46,579

A.17.2 2024 High Wind Assumptions • The 2024 renewable energy requirements for this scenario are based on the RPS requirements outlined in Table A - 13.

• Power demand was assumed to be the same; however, energy growth was increased from 1.0% to 2.0% to calculate the renewable energy

required by state in 2024 as shown in Table A - 16.

• The process for determining the wind nameplate capacity by state was similar to that used for the base cases (Table 3-4 in the main report). The

results are shown in Table A - 17.

Table A - 16: RPS Energy Requirement by State for High Wind 2024 State IA IL IN MI MN MO ND NE OH SD WI


15% 24% 15% 15% 25% 15% 16% 15% 25% 16% 24%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%


0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3





45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


63,388,261 204,512,472 153,214,626 153,041,835 95,540,127 119,766,639 16,670,847 39,554,580 226,518,212 14,847,181 99,839,034



Total 166,553,235

Table A - 17: Total Wind by State for High Wind 2024

A B C D E F G H I J

Energy to meet ~80% RPS

Requirement Existing

Wind


Incremental Wind

Prorate of NREL

by State

Energy Import/Export

by State

% RPS Wind

Energy Generated

In State

Incremental Wind

Prorate of NREL

by State Import/Export

by State

Total Wind by State



IA 7,606,591 10,109,338 -2,502,747 10,854,505 13,357,251 100% 3,278 3,918 6,331

IL 36,045,323 4,441,320 31,604,003 18,267,114 -13,336,889 63% 6,951 -3,912 8,641

IN 18,385,755 2,946,645 15,439,110 6,594,970 -8,844,140 52% 2,316 -2,594 3,351

MI 18,365,020 342,402 18,022,618 18,022,618 0 100% 6,790 0 6,919

MN 19,108,025 5,739,683 13,368,342 13,368,342 0 100% 4,204 0 6,009

MO 14,371,997 958,221 13,413,775 7,709,496 -5,704,280 60% 2,486 -1,673 2,795

ND 2,133,868 2,674,130 -540,262 12,764,834 13,305,095 100% 3,661 3,902 4,428

NE 4,746,550 540,133 4,206,417 16,028,858 11,822,441 100% 4,540 3,468 4,693

OH 28,314,777 18,641 28,296,135 14,148,068 -14,148,068 50% 5,313 -4,150 5,320

SD 1,900,439 1,019,244 881,196 12,491,757 11,610,562 100% 3,530 3,405 3,818

WI 15,574,889 1,500,588 14,074,301 6,011,979 -8,062,323 48% 2,288 -2,365 2,859

166,553,235 30,290,346 136,262,889 136,262,540 45,357 0 55,164

A.17.3 2024 Low Wind Assumptions

• Wind energy requirements were based on the existing RPS mandates and goals shown Table A - 13.

• Power demand was assumed to be the same; however, energy growth was decreased from 1.0% to 0.3% to calculate the renewable energy

requirement by state in 2024. This is shown in Table A - 18.

• The methodology for determining the wind nameplate capacity by state was similar to that adopted for the base case (Table 3-4 in the main

report). The results are shown in Table A - 19.

Table A - 18: RPS Energy Requirement by State for Low Wind 2024 State IA IL IN MI MN MO ND NE OH SD WI

State RPS Only 2% 23% 0% 10% 28% 15% 10% 15% 25% 10% 24%

% of energy renewable from wind (MWh) 80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%


0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3





45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


47,634,519 153,685,445 115,136,538 115,006,690 71,795,753 90,001,305 12,527,679 29,724,169 170,222,148 11,157,245 75,026,262


RPS energy from wind (MWh) 762,152 26,510,739 0 9,200,535 15,795,066 10,800,157 1,002,214 3,566,900 21,277,769 892,580 11,704,097

Total 101,512,209


A B C D E F G H I J

Energy to meet ~80% RPS Requirement Existing Wind






Import /Export by State

Total Wind by State Existing + Incremental


IA 762,152 10,109,338 -9,347,186 6,012,713 15,359,899 100% 1,816 4,505 4,869

IL 26,510,739 4,441,320 22,069,419 8,105,436 -13,963,984 47% 3,084 -4,096 4,774

IN 0 2,946,645 0 0 0 0 0 1,035

MI 9,200,535 342,402 8,858,133 8,858,133 0 100% 3,337 0 3,466

MN 15,795,066 5,739,683 10,055,382 10,055,382 0 100% 3,162 0 4,967

MO 10,800,157 958,221 9,841,935 4,270,576 -5,571,359 48% 1,377 -1,634 1,686

ND 1,002,214 2,674,130 -1,671,916 7,070,915 8,742,831 100% 2,028 2,564 2,795

NE 3,566,900 540,133 3,026,767 8,878,980 5,852,212 100% 2,515 1,716 2,668

OH 21,277,769 18,641 21,259,127 10,629,564 -10,629,564 50% 3,992 -3,118 3,999

SD 892,580 1,019,244 -126,664 6,919,648 7,046,312 100% 1,955 2,067 2,243

WI 11,704,097 1,500,588 10,203,509 3,367,158 -6,836,351 42% 1,281 -2,005 1,852

101,512,209 30,290,346 74,168,508 74,168,505 24,548 0 34,355

A.17.4 2019 Base Wind Assumptions

• Wind energy requirements were based on the RPS assumptions shown in Table A - 13.

• For each state in the study area, (except Wisconsin which used 1.1%), the usage was inflated by 1.0% annually through 2019. The 2019 state

renewable energy requirements are shown in Table A - 20.

• The 2019 wind nameplate capacity by state was calculated using the same methodology as in the 2029 base case (Table 3-4 in the main report).

The results are shown in Table A - 21.

Table A - 20: RPS Energy Requirement by State for Base Wind 2019





0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3

High Wind State- yes/no? (High wind state if CF>36%) Yes No No No Yes No Yes Yes No Yes No


Energy Usage by US State (MWh) / 2007 EIA 45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


51,010,832 164,578,600 123,297,364 123,158,312 76,884,604 96,380,556 13,415,635 31,831,004 182,287,417 11,948,065 81,303,888



Total 100,867,732


A B C D E F G H I J


Requirement Existing

Wind

Incremental wind to meet

~80% RPS

Incremental Wind

Prorate of NREL by State


by State

% RPS Wind Energy

Generated In State

Incremental Wind Prorate of NREL


by State

Total Wind by State Existing +

Incremental


IA 5,101,083 10,109,338 -5,008,255 5,440,234 10,448,489 100% 1,643 3,065 4,696

IL 19,749,432 4,441,320 15,308,112 7,347,894 -7,960,218 60% 2,796 -2,335 4,486

IN 12,329,736 2,946,645 9,383,091 4,120,772 -5,262,319 57% 1,447 -1,543 2,482

MI 12,315,831 342,402 11,973,429 11,973,429 0 100% 4,511 0 4,640

MN 12,301,537 5,739,683 6,561,853 6,561,853 0 100% 2,064 0 3,869

MO 9,638,056 958,221 8,679,834 3,863,968 -4,815,866 50% 1,246 -1,413 1,555

ND 1,341,564 2,674,130 -1,332,567 6,397,684 7,730,250 100% 1,835 2,267 2,602

NE 3,183,100 540,133 2,642,968 8,033,600 5,390,632 100% 2,276 1,581 2,429

OH 13,671,556 18,641 13,652,915 6,826,457 -6,826,457 50% 2,563 -2,002 2,570

SD 1,194,806 1,019,244 175,563 6,260,819 6,085,256 100% 1,769 1,785 2,057

WI 10,041,030 1,500,588 8,540,442 3,750,706 -4,789,736 52% 1,427 -1,405 1,998

100,867,732 30,290,346 70,577,386 70,577,417 23,577 0 33,384

A.17.5 2019 High Wind Assumptions

• The 2019 renewable energy requirements for this scenario are based on the RPS requirements outlined in Table A - 13.

• Power demand was assumed to be the same; however, energy growth was increased from 1.0% to 2.0% to calculate the 2019 renewable energy

required by state as shown in Table A - 22.

• The process for determining the wind nameplate capacity by state was similar to that used for the base cases (Table 3-4 in the main report). The

results are shown in Table A - 23.

Table A - 22: RPS Energy Requirement by State for High Wind 2019





0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3

High Wind State- yes/no? (high wind state if CF>36%)



Energy Usage by US State (MWh) / 2007 EIA 45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


57,412,701 185,233,247 138,771,207 138,614,705 86,533,637 108,476,335 15,099,300 35,825,802 205,164,524 13,447,549 90,427,289

% for RPS renewable (MWh) - from Line 51*58 7,176,588 29,637,319 17,346,401 17,326,838 17,306,727 13,559,542 1,887,412 4,478,225 30,774,679 1,680,944 17,181,185

RPS energy from wind (MWh) - line 52*59 5,741,270 22,227,990 13,877,121 13,861,471 13,845,382 10,847,634 1,509,930 3,582,580 15,387,339 1,344,755 11,167,770

Total 113,393,241

Table A - 23: Total Wind by State for High Wind 2019

A B C D E F G H I J


Requirement Existing Wind


Incremental Wind



by State

% RPS Wind Energy

Generated In State



by State

Total Wind by State



IA 5,741,270 10,109,338 -4,368,068 6,342,948 10,711,016 100% 1,916 3,142 4,969

IL 22,227,990 4,441,320 17,786,670 9,871,602 -7,915,068 64% 3,756 -2,322 5,446

IN 13,877,121 2,946,645 10,930,476 4,748,669 -6,181,807 55% 1,668 -1,813 2,703

MI 13,861,471 342,402 13,519,068 13,519,068 0 100% 5,093 0 5,222

MN 13,845,382 5,739,683 8,105,698 8,105,698 0 100% 2,549 0 4,354

MO 10,847,634 958,221 9,889,412 4,505,128 -5,384,284 50% 1,453 -1,579 1,762

ND 1,509,930 2,674,130 -1,164,200 7,459,269 8,623,470 100% 2,139 2,529 2,906

NE 3,582,580 540,133 3,042,447 9,366,638 6,324,190 100% 2,653 1,855 2,806

OH 15,387,339 18,641 15,368,698 7,684,349 -7,684,349 50% 2,886 -2,254 2,893

SD 1,344,755 1,019,244 325,511 7,299,694 6,974,183 100% 2,063 2,046 2,351

WI 11,167,770 1,500,588 9,667,182 4,199,840 -5,467,343 51% 1,598 -1,604 2,169

113,393,241 30,290,346 83,102,895 83,102,903 27,774 0 37,581

A.17.6 2019 Low Wind Assumptions

• The 2019 renewable energy requirements for this scenario are based on existing state RPS requirements shown in Table A - 13.

• Power demand was assumed to be the same; however, energy growth was decreased from 1.0% to 0.3% to calculate the 2019 renewable energy

requirement by state. This is shown in Table A - 24.

• The methodology for determining the wind nameplate capacity by state was similar to that adopted for the base case (Table 3-4 in the main

report). The results are shown in Table A - 25.

Table A - 24: RPS Energy Requirement by State for Low Wind 2019


State RPS Only 2% 16% 0% 10% 25% 13% 10% 13% 15% 10% 19%


80% 75% 80% 80% 80% 80% 80% 80% 50% 80% 65%


0.378 0.3 0.325 0.303 0.363 0.354 0.398 0.403 0.304 0.404 0.3





45,269,523 146,055,151 109,420,150 109,296,749 68,231,182 85,532,850 11,905,695 28,248,400 161,770,827 10,603,301 71,301,300


46,926,387 151,400,767 113,424,925 113,297,008 70,728,442 88,663,351 12,341,443 29,282,291 167,691,636 10,991,382 73,910,926


RPS energy from wind (MWh) 750,822 18,168,092 0 9,063,761 14,145,688 8,866,335 987,315 2,928,229 12,576,873 879,311 9,127,999

Total 77,494,425


A B C D E F G H I J


Requirement Existing Wind


Incremental Wind



by State

% RPS Wind Energy

Generated In State



by State

Total Wind by State



IA 750,822 10,109,338 -9,358,516 3,472,628 12,831,143 100% 1,049 3,763 4,102

IL 18,168,092 4,441,320 13,726,772 4,667,102 -9,059,670 50% 1,776 -2,657 3,466

IN 0 2,946,645 0 0 0 0 0 1,035

MI 9,063,761 342,402 8,721,359 8,721,359 0 100% 3,286 0 3,415

MN 14,145,688 5,739,683 8,406,005 8,406,005 0 100% 2,643 0 4,448

MO 8,866,335 958,221 7,908,114 2,466,461 -5,441,653 39% 795 -1,596 1,104

ND 987,315 2,674,130 -1,686,815 4,083,790 5,770,604 100% 1,171 1,693 1,938

NE 2,928,229 540,133 2,388,096 5,128,033 2,739,937 100% 1,453 804 1,606

OH 12,576,873 18,641 12,558,231 6,279,116 -6,279,116 50% 2,358 -1,842 2,365

SD 879,311 1,019,244 -139,933 3,996,426 4,136,359 100% 1,129 1,213 1,417

WI 9,127,999 1,500,588 7,627,411 2,929,803 -4,697,608 49% 1,115 -1,378 1,686

77,494,425 30,290,346 50,150,725 50,150,721 16,775 0 26,582

81

B Appendix B: Study Methodology

B.1 Futures B.1.1 Base Case

Based on the key assumptions detailed in Appendix A, 2029 on and off peak cases were developed. The

wind energy calculations were based on 1.0% annual energy growth and the Renewable Portfolio

Standard (RPS) requirements as shown in Table 3-1 of the main report. The methodologies used to

develop the wind generation capacity by state for the 2029 base case are discussed in Section 3 of the

main body of the report

The transmission alternatives were designed to meet the performance criteria under base case

assumptions. In addition to the 2029 base cases, two generation future cases were created to evaluate the

robustness of the alternatives. Futures analysis takes into account the uncertainties surrounding public

policy and economic drivers that may impact the generation portfolio. The alternatives were tested under

High Gas and Low Carbon Future scenarios.

B.1.2 High Gas Future

The High Gas Future assumes that gas will be the preferred technology for new generation development.

This Future was included due to its smaller environmental footprint as compared to other fossil fuels, its

flexibility in terms of use, and shorter plant construction timeframe. The following adjustments were

made to the on and off peak base cases to develop corresponding high gas future cases.

• Wind generation used to develop the high gas future cases remained the same as the base

cases.

• An additional 11.6 GW of gas generation was added.

• Existing coal units were reduced to accommodate the additional gas unit generation.

B.1.3 Low Carbon Future

The Low Carbon Future is based on the premise of reducing the output of carbon emitting generation

resources. The following adjustments were made to the on and off peak base cases to develop

corresponding low carbon future cases.

• The wind generation used for developing the low carbon future cases was the same as for the

base cases.

• Approximately 1 GW of hydro power was added.

• Approximately 1 GW of nuclear generation was added.

• Approximately 4 GW of gas generation was added.

• Approximately 2 GW of wind generation was added in North and South Dakota and

Minnesota.

• Approximately 3 GW of wind generation was imported from SPP

• Coal units with maximum nameplate ratings of 250 MW that were 40 years or older in 2010

were retired. This resulted in a reduction of 2 GW of coal generation.

82

• The remaining 9 GW was accounted for by reducing the output of existing coal units.

B.2 Sensitivities To test the alternatives for robustness under specific conditions, sensitivities were run for generation and

load cases. Generation cases were run for the off peak base cases. Load cases were run for the on peak

base cases.

B.2.1 High Wind

The high wind generation sensitivity was designed to address the higher than expected energy usage that

would be associated with economic growth during the 20-year period. For this sensitivity, the renewable

requirements were based on 2.0% energy growth as opposed to the 1.0% assumed in the base case. This

equates to a need for an additional 13 GW of nameplate wind generation. Table A - 9 and Table A - 10 in

Appendix A show the calculations for the wind nameplate values by state. The high wind generation

sensitivity was applied to the off peak base and futures cases. The low demand levels and high wind

generation availability during off peak hours result in high loading on the transmission facilities. The off

peak case was therefore considered as an appropriate measure for robustness. To account for the excess

wind generation, the models simulated energy transfers by creating load sinks (~8.4GW) along the eastern

border of AEP’s service territory.

B.2.2 Low Wind

The low wind generation sensitivity was designed to address uncertainties surrounding renewable energy

polices and take into account lower than anticipated energy growth during the 20-year study period.

Renewable requirements were based on existing RPS requirements (Table 3-1 in the main report) and

energy growth of 0.3% as opposed to 1.0% in the base case.

Table A - 12 calculates the wind nameplate values by state that result in a total reduction of 20 GW wind

power.

B.2.3 High Wind Import from SPP

Given the significant wind activity in SPP, this sensitivity provides insight into the contribution of the

SPP wind generation to the eastern market. Approximately, 3 GW of wind imports from the SPP region

were modeled in the off peak case. To account for the imports, the models simulated energy transfers by

creating load sinks along the eastern border of AEP’s service territory. The Study applied this sensitivity

to the off peak cases due to high wind availability during off peak hours. The SPP imports result in

increased west to east line loading levels on the transmission overlays.

B.2.4 Higher than forecasted load growth

83

This sensitivity tests for stronger than anticipated economic growth during the 20 year period. The load

levels in the base and future on peak cases were increased by 1.0% for all the control areas. This resulted

in 2 GW of additional load as compared to the base case.

B.2.5 Lower than forecasted load growth

This sensitivity was designed to test the impact of increased energy efficiency, demand side management

and weak economic growth. The load levels in the base and Future on peak cases were decreased by 5%

for the control areas. This resulted in a load reduction of 8 GW as compared to the base case.

B.3 2019 and 2024 Analysis After the 2029 EHV Overlay alternatives were defined, transmission upgrade requirements for 2024 and

2019 were developed. This sequencing process was used to facilitate an efficient build out of the

transmission overlay in an effort to preclude the development of a piecemeal transmission system that

only considers immediate needs. The overlays were sensitivity tested for high and low wind, higher than

forecasted load growth, and SPP Imports.

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